National Library of Energy BETA

Sample records for oil reservoir considered

  1. Texas--State Offshore Crude Oil Reserves in Nonproducing Reservoirs...

    Gasoline and Diesel Fuel Update (EIA)

    Crude Oil Reserves in Nonproducing Reservoirs (Million Barrels) Texas--State Offshore Crude Oil Reserves in Nonproducing Reservoirs (Million Barrels) Decade Year-0 Year-1 Year-2 ...

  2. Louisiana--North Crude Oil Reserves in Nonproducing Reservoirs...

    U.S. Energy Information Administration (EIA) Indexed Site

    Crude Oil Reserves in Nonproducing Reservoirs (Million Barrels) Louisiana--North Crude Oil Reserves in Nonproducing Reservoirs (Million Barrels) Decade Year-0 Year-1 Year-2 Year-3 ...

  3. ,"West Virginia Crude Oil Reserves in Nonproducing Reservoirs...

    U.S. Energy Information Administration (EIA) Indexed Site

    Data for" ,"Data 1","West Virginia Crude Oil Reserves in Nonproducing Reservoirs ... to Contents","Data 1: West Virginia Crude Oil Reserves in Nonproducing Reservoirs ...

  4. ,"New York Crude Oil Reserves in Nonproducing Reservoirs (Million...

    U.S. Energy Information Administration (EIA) Indexed Site

    Crude Oil Reserves in Nonproducing Reservoirs (Million Barrels)" ,"Click worksheet name or ... Data for" ,"Data 1","New York Crude Oil Reserves in Nonproducing Reservoirs ...

  5. ,"Miscellaneous States Crude Oil Reserves in Nonproducing Reservoirs...

    U.S. Energy Information Administration (EIA) Indexed Site

    for" ,"Data 1","Miscellaneous States Crude Oil Reserves in Nonproducing Reservoirs ... Contents","Data 1: Miscellaneous States Crude Oil Reserves in Nonproducing Reservoirs ...

  6. ,"North Dakota Crude Oil Reserves in Nonproducing Reservoirs...

    U.S. Energy Information Administration (EIA) Indexed Site

    Data for" ,"Data 1","North Dakota Crude Oil Reserves in Nonproducing Reservoirs ... to Contents","Data 1: North Dakota Crude Oil Reserves in Nonproducing Reservoirs ...

  7. RESEARCH OIL RECOVERY MECHANISMS IN HEAVY OIL RESERVOIRS

    SciTech Connect (OSTI)

    Anthony R. Kovscek; William E. Brigham

    1999-06-01

    The United States continues to rely heavily on petroleum fossil fuels as a primary energy source, while domestic reserves dwindle. However, so-called heavy oil (10 to 20{sup o}API) remains an underutilized resource of tremendous potential. Heavy oils are much more viscous than conventional oils. As a result, they are difficult to produce with conventional recovery methods such as pressure depletion and water injection. Thermal recovery is especially important for this class of reservoirs because adding heat, usually via steam injection, generally reduces oil viscosity dramatically. This improves displacement efficiency. The research described here was directed toward improved understanding of thermal and heavy-oil production mechanisms and is categorized into: (1) flow and rock properties; (2) in-situ combustion; (3) additives to improve mobility control; (4) reservoir definition; and (5) support services. The scope of activities extended over a three-year period. Significant work was accomplished in the area of flow properties of steam, water, and oil in consolidated and unconsolidated porous media, transport in fractured porous media, foam generation and flow in homogeneous and heterogeneous porous media, the effects of displacement pattern geometry and mobility ratio on oil recovery, and analytical representation of water influx. Significant results are described.

  8. Reservoir Engineering for Unconventional Gas Reservoirs: What Do We Have to Consider?

    SciTech Connect (OSTI)

    Clarkson, Christopher R

    2011-01-01

    The reservoir engineer involved in the development of unconventional gas reservoirs (UGRs) is required to integrate a vast amount of data from disparate sources, and to be familiar with the data collection and assessment. There has been a rapid evolution of technology used to characterize UGR reservoir and hydraulic fracture properties, and there currently are few standardized procedures to be used as guidance. Therefore, more than ever, the reservoir engineer is required to question data sources and have an intimate knowledge of evaluation procedures. We propose a workflow for the optimization of UGR field development to guide discussion of the reservoir engineer's role in the process. Critical issues related to reservoir sample and log analysis, rate-transient and production data analysis, hydraulic and reservoir modeling and economic analysis are raised. Further, we have provided illustrations of each step of the workflow using tight gas examples. Our intent is to provide some guidance for best practices. In addition to reviewing existing methods for reservoir characterization, we introduce new methods for measuring pore size distribution (small-angle neutron scattering), evaluating core-scale heterogeneity, log-core calibration, evaluating core/log data trends to assist with scale-up of core data, and modeling flow-back of reservoir fluids immediately after well stimulation. Our focus in this manuscript is on tight and shale gas reservoirs; reservoir characterization methods for coalbed methane reservoirs have recently been discussed.

  9. Texas--RRC District 1 Crude Oil Reserves in Nonproducing Reservoirs...

    Annual Energy Outlook [U.S. Energy Information Administration (EIA)]

    Crude Oil Reserves in Nonproducing Reservoirs (Million Barrels) Texas--RRC District 1 Crude Oil Reserves in Nonproducing Reservoirs (Million Barrels) Decade Year-0 Year-1 Year-2 ...

  10. Texas--RRC District 9 Crude Oil Reserves in Nonproducing Reservoirs...

    Annual Energy Outlook [U.S. Energy Information Administration (EIA)]

    Crude Oil Reserves in Nonproducing Reservoirs (Million Barrels) Texas--RRC District 9 Crude Oil Reserves in Nonproducing Reservoirs (Million Barrels) Decade Year-0 Year-1 Year-2 ...

  11. Texas--RRC District 5 Crude Oil Reserves in Nonproducing Reservoirs...

    Gasoline and Diesel Fuel Update (EIA)

    Crude Oil Reserves in Nonproducing Reservoirs (Million Barrels) Texas--RRC District 5 Crude Oil Reserves in Nonproducing Reservoirs (Million Barrels) Decade Year-0 Year-1 Year-2 ...

  12. Texas--RRC District 6 Crude Oil Reserves in Nonproducing Reservoirs...

    Annual Energy Outlook [U.S. Energy Information Administration (EIA)]

    Crude Oil Reserves in Nonproducing Reservoirs (Million Barrels) Texas--RRC District 6 Crude Oil Reserves in Nonproducing Reservoirs (Million Barrels) Decade Year-0 Year-1 Year-2 ...

  13. Texas--RRC District 10 Crude Oil Reserves in Nonproducing Reservoirs...

    Gasoline and Diesel Fuel Update (EIA)

    Crude Oil Reserves in Nonproducing Reservoirs (Million Barrels) Texas--RRC District 10 Crude Oil Reserves in Nonproducing Reservoirs (Million Barrels) Decade Year-0 Year-1 Year-2 ...

  14. Texas--RRC District 8 Crude Oil Reserves in Nonproducing Reservoirs...

    Annual Energy Outlook [U.S. Energy Information Administration (EIA)]

    Crude Oil Reserves in Nonproducing Reservoirs (Million Barrels) Texas--RRC District 8 Crude Oil Reserves in Nonproducing Reservoirs (Million Barrels) Decade Year-0 Year-1 Year-2 ...

  15. Opportunities to improve oil productivity in unstructured deltaic reservoirs

    SciTech Connect (OSTI)

    Not Available

    1991-01-01

    This report contains presentations presented at a technical symposium on oil production. Chapter 1 contains summaries of the presentations given at the Department of Energy (DOE)-sponsored symposium and key points of the discussions that followed. Chapter 2 characterizes the light oil resource from fluvial-dominated deltaic reservoirs in the Tertiary Oil Recovery Information System (TORIS). An analysis of enhanced oil recovery (EOR) and advanced secondary recovery (ASR) potential for fluvial-dominated deltaic reservoirs based on recovery performance and economic modeling as well as the potential resource loss due to well abandonments is presented. Chapter 3 provides a summary of the general reservoir characteristics and properties within deltaic deposits. It is not exhaustive treatise, rather it is intended to provide some basic information about geologic, reservoir, and production characteristics of deltaic reservoirs, and the resulting recovery problems.

  16. Increasing Waterflooding Reservoirs in the Wilmington Oil Field through Improved Reservoir Characterization and Reservoir Management

    SciTech Connect (OSTI)

    Clarke, Don; Koerner, Roy; Moos, Dan; Nguyen, John; Phillips, Chris; Tagbor, Kwasi; Walker, Scott

    1999-11-09

    The objectives of this quarterly report are to summarize the work conducted under each task during the reporting period July - September 1998 and to report all technical data and findings as specified in the ''Federal Assistance Reporting Checklist''. The main objective of this project is the transfer of technologies, methodologies, and findings developed and applied in this project to other operators of Slope and Basin Clastic Reservoirs. This project will study methods to identify sands with high remaining oil saturation and to recomplete existing wells using advanced completion technology.

  17. Increasing Waterflooding Reservoirs in the Wilmington Oil Field through Improved Reservoir Characterization and Reservoir Management

    SciTech Connect (OSTI)

    Koerner, Roy; Clarke, Don; Walker, Scott

    1999-11-09

    The objectives of this quarterly report was to summarize the work conducted under each task during the reporting period April - June 1998 and to report all technical data and findings as specified in the ''Federal Assistance Reporting Checklist''. The main objective of this project is the transfer of technologies, methodologies, and findings developed and applied in this project to other operators of Slope and Basin Clastic Reservoirs. This project will study methods to identify sands with high remaining oil saturation and to recomplete existing wells using advanced completion technology.

  18. Increasing Waterflooding Reservoirs in the Wilmington Oil Field through Improved Reservoir Characterization and Reservoir Management, Class III

    SciTech Connect (OSTI)

    Koerner, Roy; Clarke, Don; Walker, Scott; Phillips, Chris; Nguyen, John; Moos, Dan; Tagbor, Kwasi

    2001-08-07

    This project was intended to increase recoverable waterflood reserves in slope and basin reservoirs through improved reservoir characterization and reservoir management. The particular application of this project is in portions of Fault Blocks IV and V of the Wilmington Oil Field, in Long Beach, California, but the approach is widely applicable in slope and basin reservoirs, transferring technology so that it can be applied in other sections of the Wilmington field and by operators in other slope and basin reservoirs is a primary component of the project.

  19. Increasing Waterflood Reserves in the Wilmington Oil Field Through Reservoir Characterization and Reservoir Management

    SciTech Connect (OSTI)

    Chris Phillips; Dan Moos; Don Clarke; John Nguyen; Kwasi Tagbor; Roy Koerner; Scott Walker

    1997-04-10

    This project is intended to increase recoverable waterflood reserves in slope and basin reservoirs through improved reservoir characterization and reservoir management. The particular application of this project is in portions of Fault Blocks IV and V of the Wilmington Oil Field, in Long Beach, California, but the approach is widely applicable in slope and basin reservoirs. Transferring technology so that it can be applied in other sections of the Wilmington Field and by operators in other slope and basin reservoirs is a primary component of the project.

  20. Alaska Crude Oil + Lease Condensate New Reservoir Discoveries...

    U.S. Energy Information Administration (EIA) Indexed Site

    Crude Oil + Lease Condensate New Reservoir Discoveries in Old Fields (Million Barrels) Decade Year-0 Year-1 Year-2 Year-3 Year-4 Year-5 Year-6 Year-7 Year-8 Year-9 2000's 0 2010's...

  1. Evaluation of Reservoir Wettability and its Effect on Oil Recovery.

    Office of Scientific and Technical Information (OSTI)

    (Technical Report) | SciTech Connect Technical Report: Evaluation of Reservoir Wettability and its Effect on Oil Recovery. Citation Details In-Document Search Title: Evaluation of Reservoir Wettability and its Effect on Oil Recovery. × You are accessing a document from the Department of Energy's (DOE) SciTech Connect. This site is a product of DOE's Office of Scientific and Technical Information (OSTI) and is provided as a public service. Visit OSTI to utilize additional information

  2. Heavy oil reservoirs recoverable by thermal technology. Annual report

    SciTech Connect (OSTI)

    Kujawa, P.

    1981-02-01

    The purpose of this study was to compile data on reservoirs that contain heavy oil in the 8 to 25/sup 0/ API gravity range, contain at least ten million barrels of oil currently in place, and are non-carbonate in lithology. The reservoirs within these constraints were then analyzed in light of applicable recovery technology, either steam-drive or in situ combustion, and then ranked hierarchically as candidate reservoirs. The study is presented in three volumes. Volume I presents the project background and approach, the screening analysis, ranking criteria, and listing of candidate reservoirs. The economic and environmental aspects of heavy oil recovery are included in appendices to this volume. This study provides an extensive basis for heavy oil development, but should be extended to include carbonate reservoirs and tar sands. It is imperative to look at heavy oil reservoirs and projects on an individual basis; it was discovered that operators, and industrial and government analysts will lump heavy oil reservoirs as poor producers, however, it was found that upon detailed analysis, a large number, so categorized, were producing very well. A study also should be conducted on abandoned reservoirs. To utilize heavy oil, refiners will have to add various unit operations to their processes, such as hydrotreaters and hydrodesulfurizers and will require, in most cases, a lighter blending stock. A big problem in producing heavy oil is that of regulation; specifically, it was found that the regulatory constraints are so fluid and changing that one cannot settle on a favorable recovery and production plan with enough confidence in the regulatory requirements to commit capital to the project.

  3. Increasing Waterflood Reserves in the Wilmington Oil Field through Improved Reservoir Characterization and Reservoir Management

    SciTech Connect (OSTI)

    Clarke, D.; Koerner, R.; Moos D.; Nguyen, J.; Phillips, C.; Tagbor, K.; Walker, S.

    1999-04-05

    This project used advanced reservoir characterization tools, including the pulsed acoustic cased-hole logging tool, geologic three-dimensional (3-D) modeling software, and commercially available reservoir management software to identify sands with remaining high oil saturation following waterflood. Production from the identified high oil saturated sands was stimulated by recompleting existing production and injection wells in these sands using conventional means as well as a short radius redrill candidate.

  4. INCREASING WATERFLOOD RESERVES IN THE WILMINGTON OIL FIELD THROUGH IMPROVED RESERVOIR CHARACTERIZATION AND RESERVOIR MANAGEMENT

    SciTech Connect (OSTI)

    Scott Walker; Chris Phillips; Roy Koerner; Don Clarke; Dan Moos; Kwasi Tagbor

    2002-02-28

    This project increased recoverable waterflood reserves in slope and basin reservoirs through improved reservoir characterization and reservoir management. The particular application of this project is in portions of Fault Blocks IV and V of the Wilmington Oil Field, in Long Beach, California, but the approach is widely applicable in slope and basin reservoirs. Transferring technology so that it can be applied in other sections of the Wilmington Field and by operators in other slope and basin reservoirs is a primary component of the project. This project used advanced reservoir characterization tools, including the pulsed acoustic cased-hole logging tool, geologic three-dimensional (3-D) modeling software, and commercially available reservoir management software to identify sands with remaining high oil saturation following waterflood. Production from the identified high oil saturated sands was stimulated by recompleting existing production and injection wells in these sands using conventional means as well as a short radius redrill candidate. Although these reservoirs have been waterflooded over 40 years, researchers have found areas of remaining oil saturation. Areas such as the top sand in the Upper Terminal Zone Fault Block V, the western fault slivers of Upper Terminal Zone Fault Block V, the bottom sands of the Tar Zone Fault Block V, and the eastern edge of Fault Block IV in both the Upper Terminal and Lower Terminal Zones all show significant remaining oil saturation. Each area of interest was uncovered emphasizing a different type of reservoir characterization technique or practice. This was not the original strategy but was necessitated by the different levels of progress in each of the project activities.

  5. U.S. Federal Offshore Crude Oil Reserves in Nonproducing Reservoirs...

    Gasoline and Diesel Fuel Update (EIA)

    Reserves in Nonproducing Reservoirs (Million Barrels) U.S. Federal Offshore Crude Oil Reserves in Nonproducing Reservoirs (Million Barrels) Decade Year-0 Year-1 Year-2 Year-3...

  6. Ohio Crude Oil Reserves in Nonproducing Reservoirs (Million Barrels)

    U.S. Energy Information Administration (EIA) Indexed Site

    Reserves in Nonproducing Reservoirs (Million Barrels) Ohio Crude Oil Reserves in Nonproducing Reservoirs (Million Barrels) Decade Year-0 Year-1 Year-2 Year-3 Year-4 Year-5 Year-6 Year-7 Year-8 Year-9 1990's NA NA 0 17 2000's 10 6 8 8 7 7 8 8 7 5 2010's 1 1 2 7 3 - = No Data Reported; -- = Not Applicable; NA = Not Available; W = Withheld to avoid disclosure of individual company data. Release Date: 11/19/2015 Next Release Date: 12/31/2016 Referring Pages: Proved Nonproducing Reserves of Crude Oil

  7. Louisiana--South Onshore Crude Oil Reserves in Nonproducing Reservoirs

    U.S. Energy Information Administration (EIA) Indexed Site

    (Million Barrels) Crude Oil Reserves in Nonproducing Reservoirs (Million Barrels) Louisiana--South Onshore Crude Oil Reserves in Nonproducing Reservoirs (Million Barrels) Decade Year-0 Year-1 Year-2 Year-3 Year-4 Year-5 Year-6 Year-7 Year-8 Year-9 1990's NA NA 143 146 2000's 123 134 139 150 115 148 162 164 122 129 2010's 126 113 125 155 188 - = No Data Reported; -- = Not Applicable; NA = Not Available; W = Withheld to avoid disclosure of individual company data. Release Date: 11/19/2015 Next

  8. Louisiana--State Offshore Crude Oil Reserves in Nonproducing Reservoirs

    U.S. Energy Information Administration (EIA) Indexed Site

    (Million Barrels) Crude Oil Reserves in Nonproducing Reservoirs (Million Barrels) Louisiana--State Offshore Crude Oil Reserves in Nonproducing Reservoirs (Million Barrels) Decade Year-0 Year-1 Year-2 Year-3 Year-4 Year-5 Year-6 Year-7 Year-8 Year-9 1990's NA NA 37 38 2000's 50 66 30 26 24 28 22 18 13 12 2010's 12 9 19 13 16 - = No Data Reported; -- = Not Applicable; NA = Not Available; W = Withheld to avoid disclosure of individual company data. Release Date: 11/19/2015 Next Release Date:

  9. Alabama (with State Offshore) Crude Oil Reserves in Nonproducing Reservoirs

    U.S. Energy Information Administration (EIA) Indexed Site

    (Million Barrels) Crude Oil Reserves in Nonproducing Reservoirs (Million Barrels) Alabama (with State Offshore) Crude Oil Reserves in Nonproducing Reservoirs (Million Barrels) Decade Year-0 Year-1 Year-2 Year-3 Year-4 Year-5 Year-6 Year-7 Year-8 Year-9 1990's NA NA 4 2 2000's 2 4 1 2 2 2 0 0 0 0 2010's 0 1 2 2 15 - = No Data Reported; -- = Not Applicable; NA = Not Available; W = Withheld to avoid disclosure of individual company data. Release Date: 11/19/2015 Next Release Date: 12/31/2016

  10. Alaska (with Total Offshore) Crude Oil Reserves in Nonproducing Reservoirs

    U.S. Energy Information Administration (EIA) Indexed Site

    (Million Barrels) Crude Oil Reserves in Nonproducing Reservoirs (Million Barrels) Alaska (with Total Offshore) Crude Oil Reserves in Nonproducing Reservoirs (Million Barrels) Decade Year-0 Year-1 Year-2 Year-3 Year-4 Year-5 Year-6 Year-7 Year-8 Year-9 1990's NA NA 806 932 2000's 511 389 546 734 707 595 442 400 529 633 2010's 622 566 802 639 548 - = No Data Reported; -- = Not Applicable; NA = Not Available; W = Withheld to avoid disclosure of individual company data. Release Date: 11/19/2015

  11. California--State Offshore Crude Oil Reserves in Nonproducing Reservoirs

    U.S. Energy Information Administration (EIA) Indexed Site

    (Million Barrels) Crude Oil Reserves in Nonproducing Reservoirs (Million Barrels) California--State Offshore Crude Oil Reserves in Nonproducing Reservoirs (Million Barrels) Decade Year-0 Year-1 Year-2 Year-3 Year-4 Year-5 Year-6 Year-7 Year-8 Year-9 1990's NA NA 7 0 2000's 32 30 42 25 30 35 34 27 23 46 2010's 47 62 53 52 46 - = No Data Reported; -- = Not Applicable; NA = Not Available; W = Withheld to avoid disclosure of individual company data. Release Date: 11/19/2015 Next Release Date:

  12. Federal Offshore--California Crude Oil Reserves in Nonproducing Reservoirs

    U.S. Energy Information Administration (EIA) Indexed Site

    (Million Barrels) Crude Oil Reserves in Nonproducing Reservoirs (Million Barrels) Federal Offshore--California Crude Oil Reserves in Nonproducing Reservoirs (Million Barrels) Decade Year-0 Year-1 Year-2 Year-3 Year-4 Year-5 Year-6 Year-7 Year-8 Year-9 1990's NA NA 21 15 2000's 42 62 62 93 55 32 37 20 12 12 2010's 13 13 25 17 18 - = No Data Reported; -- = Not Applicable; NA = Not Available; W = Withheld to avoid disclosure of individual company data. Release Date: 11/19/2015 Next Release

  13. Illinois Crude Oil Reserves in Nonproducing Reservoirs (Million Barrels)

    U.S. Energy Information Administration (EIA) Indexed Site

    Reserves in Nonproducing Reservoirs (Million Barrels) Illinois Crude Oil Reserves in Nonproducing Reservoirs (Million Barrels) Decade Year-0 Year-1 Year-2 Year-3 Year-4 Year-5 Year-6 Year-7 Year-8 Year-9 1990's NA NA 4 11 2000's 4 15 0 0 0 0 - = No Data Reported; -- = Not Applicable; NA = Not Available; W = Withheld to avoid disclosure of individual company data. Release Date: 11/19/2015 Next Release Date: 12/31/2016 Referring Pages: Proved Nonproducing Reserves of Crude Oil Illinois Proved

  14. Field development options for a waterflooded heavy-oil reservoir

    SciTech Connect (OSTI)

    Kasraie, M. ); Sammon, P.H. ); Jespersen, P.J. )

    1993-09-01

    Battrum Unit 4 is a moderately heavy-oil reservoir in Saskatchewan producing under waterflood from a thin sand. This paper describes a history match of previous field behavior and systematically analyzes through the use of numerical simulation the potential benefits to production of further waterflooding (with and without infill drilling), steamflooding, and horizontal drilling. It is found that the remaining oil recovery potential of a steamflood with horizontal well is significantly higher than that of any of the waterflood options.

  15. Texas--RRC District 8A Crude Oil Reserves in Nonproducing Reservoirs...

    Annual Energy Outlook [U.S. Energy Information Administration (EIA)]

    Crude Oil Reserves in Nonproducing Reservoirs (Million Barrels) Texas--RRC District 8A Crude Oil Reserves in Nonproducing Reservoirs (Million Barrels) Decade Year-0 Year-1 Year-2 ...

  16. Texas--RRC District 7C Crude Oil Reserves in Nonproducing Reservoirs...

    Annual Energy Outlook [U.S. Energy Information Administration (EIA)]

    Crude Oil Reserves in Nonproducing Reservoirs (Million Barrels) Texas--RRC District 7C Crude Oil Reserves in Nonproducing Reservoirs (Million Barrels) Decade Year-0 Year-1 Year-2 ...

  17. Texas--RRC District 7B Crude Oil Reserves in Nonproducing Reservoirs...

    Gasoline and Diesel Fuel Update (EIA)

    Crude Oil Reserves in Nonproducing Reservoirs (Million Barrels) Texas--RRC District 7B Crude Oil Reserves in Nonproducing Reservoirs (Million Barrels) Decade Year-0 Year-1 Year-2 ...

  18. Heavy oil reservoirs recoverable by thermal technology. Annual report

    SciTech Connect (OSTI)

    Kujawa, P.

    1981-02-01

    This volume contains reservoir, production, and project data for target reservoirs thermally recoverable by steam drive which are equal to or greater than 2500 feet deep and contain heavy oil in the 8 to 25/sup 0/ API gravity range. Data were collected from three source types: hands-on (A), once-removed (B), and twice-removed (C). In all cases, data were sought depicting and characterizing individual reservoirs as opposed to data covering an entire field with more than one producing interval or reservoir. The data sources are listed at the end of each case. This volume also contains a complete listing of operators and projects, as well as a bibliography of source material.

  19. Evaluation of Reservoir Wettability and its Effect on Oil Recovery

    SciTech Connect (OSTI)

    Jill S. Buckley

    1998-06-12

    This project has three main goals. The first is to achieve improved understanding of the surface and interfacial properties of crude oils and their interactions with mineral surfaces. The second goal is to apply the results of surface studies to improved predictions of oil production in laboratory experiments. Finally, we aim to use the results of this research to recommend ways to improve oil recovery by waterflooding. In order to achieve these goals, the mechanisms of wetting alteration must be explained. We propose a methodology for studying those mechanisms on mineral surfaces, then applying the results to prediction and observation of wetting alteration in porous media. Improved understanding of the underlying mechanisms will show when and how wettability in the reservoir can be altered and under what circumstances that alteration would be beneficial in terms of increased production of oil. In the work reported this quarter, crude oil interactions with Berea sandstone have been used to prepare cores with mixed wettability.

  20. North Dakota Crude Oil Reserves in Nonproducing Reservoirs (Million

    U.S. Energy Information Administration (EIA) Indexed Site

    Barrels) Reserves in Nonproducing Reservoirs (Million Barrels) North Dakota Crude Oil Reserves in Nonproducing Reservoirs (Million Barrels) Decade Year-0 Year-1 Year-2 Year-3 Year-4 Year-5 Year-6 Year-7 Year-8 Year-9 1990's NA NA 17 22 2000's 29 91 62 47 52 56 53 107 148 463 2010's 969 1,421 2,207 3,278 3,456 - = No Data Reported; -- = Not Applicable; NA = Not Available; W = Withheld to avoid disclosure of individual company data. Release Date: 11/19/2015 Next Release Date: 12/31/2016

  1. Oklahoma Crude Oil Reserves in Nonproducing Reservoirs (Million Barrels)

    U.S. Energy Information Administration (EIA) Indexed Site

    Reserves in Nonproducing Reservoirs (Million Barrels) Oklahoma Crude Oil Reserves in Nonproducing Reservoirs (Million Barrels) Decade Year-0 Year-1 Year-2 Year-3 Year-4 Year-5 Year-6 Year-7 Year-8 Year-9 1990's NA NA 98 80 2000's 111 109 105 92 92 101 90 118 129 138 2010's 143 244 279 292 444 - = No Data Reported; -- = Not Applicable; NA = Not Available; W = Withheld to avoid disclosure of individual company data. Release Date: 11/19/2015 Next Release Date: 12/31/2016 Referring Pages: Proved

  2. Pennsylvania Crude Oil Reserves in Nonproducing Reservoirs (Million

    U.S. Energy Information Administration (EIA) Indexed Site

    Barrels) Reserves in Nonproducing Reservoirs (Million Barrels) Pennsylvania Crude Oil Reserves in Nonproducing Reservoirs (Million Barrels) Decade Year-0 Year-1 Year-2 Year-3 Year-4 Year-5 Year-6 Year-7 Year-8 Year-9 1990's NA NA 0 5 2000's 1 1 1 1 1 0 0 0 1 0 2010's 0 0 0 0 0 - = No Data Reported; -- = Not Applicable; NA = Not Available; W = Withheld to avoid disclosure of individual company data. Release Date: 11/19/2015 Next Release Date: 12/31/2016 Referring Pages: Proved Nonproducing

  3. Michigan Crude Oil Reserves in Nonproducing Reservoirs (Million Barrels)

    U.S. Energy Information Administration (EIA) Indexed Site

    Reserves in Nonproducing Reservoirs (Million Barrels) Michigan Crude Oil Reserves in Nonproducing Reservoirs (Million Barrels) Decade Year-0 Year-1 Year-2 Year-3 Year-4 Year-5 Year-6 Year-7 Year-8 Year-9 1990's NA NA 3 1 2000's 4 6 4 14 10 17 15 2 9 6 2010's 0 0 0 4 3 - = No Data Reported; -- = Not Applicable; NA = Not Available; W = Withheld to avoid disclosure of individual company data. Release Date: 11/19/2015 Next Release Date: 12/31/2016 Referring Pages: Proved Nonproducing Reserves of

  4. Miscellaneous States Crude Oil Reserves in Nonproducing Reservoirs (Million

    U.S. Energy Information Administration (EIA) Indexed Site

    Barrels) Reserves in Nonproducing Reservoirs (Million Barrels) Miscellaneous States Crude Oil Reserves in Nonproducing Reservoirs (Million Barrels) Decade Year-0 Year-1 Year-2 Year-3 Year-4 Year-5 Year-6 Year-7 Year-8 Year-9 1990's NA NA 1 1 2000's 1 1 16 17 4 4 2 5 4 7 2010's 5 7 12 9 6 - = No Data Reported; -- = Not Applicable; NA = Not Available; W = Withheld to avoid disclosure of individual company data. Release Date: 11/19/2015 Next Release Date: 12/31/2016 Referring Pages: Proved

  5. Montana Crude Oil Reserves in Nonproducing Reservoirs (Million Barrels)

    U.S. Energy Information Administration (EIA) Indexed Site

    Reserves in Nonproducing Reservoirs (Million Barrels) Montana Crude Oil Reserves in Nonproducing Reservoirs (Million Barrels) Decade Year-0 Year-1 Year-2 Year-3 Year-4 Year-5 Year-6 Year-7 Year-8 Year-9 1990's NA NA 6 83 2000's 36 43 65 79 104 88 91 90 50 42 2010's 74 59 95 104 155 - = No Data Reported; -- = Not Applicable; NA = Not Available; W = Withheld to avoid disclosure of individual company data. Release Date: 11/19/2015 Next Release Date: 12/31/2016 Referring Pages: Proved Nonproducing

  6. New Mexico Crude Oil Reserves in Nonproducing Reservoirs (Million Barrels)

    U.S. Energy Information Administration (EIA) Indexed Site

    Reserves in Nonproducing Reservoirs (Million Barrels) New Mexico Crude Oil Reserves in Nonproducing Reservoirs (Million Barrels) Decade Year-0 Year-1 Year-2 Year-3 Year-4 Year-5 Year-6 Year-7 Year-8 Year-9 1990's NA NA 97 157 2000's 91 161 146 133 142 171 159 147 136 149 2010's 180 185 232 314 489 - = No Data Reported; -- = Not Applicable; NA = Not Available; W = Withheld to avoid disclosure of individual company data. Release Date: 11/19/2015 Next Release Date: 12/31/2016 Referring Pages:

  7. Arkansas Crude Oil Reserves in Nonproducing Reservoirs (Million Barrels)

    U.S. Energy Information Administration (EIA) Indexed Site

    Reserves in Nonproducing Reservoirs (Million Barrels) Arkansas Crude Oil Reserves in Nonproducing Reservoirs (Million Barrels) Decade Year-0 Year-1 Year-2 Year-3 Year-4 Year-5 Year-6 Year-7 Year-8 Year-9 1990's NA NA 2 5 2000's 7 4 5 2 3 2 1 0 0 0 2010's 1 0 11 10 8 - = No Data Reported; -- = Not Applicable; NA = Not Available; W = Withheld to avoid disclosure of individual company data. Release Date: 11/19/2015 Next Release Date: 12/31/2016 Referring Pages: Proved Nonproducing Reserves of Crude

  8. Colorado Crude Oil Reserves in Nonproducing Reservoirs (Million Barrels)

    U.S. Energy Information Administration (EIA) Indexed Site

    Reserves in Nonproducing Reservoirs (Million Barrels) Colorado Crude Oil Reserves in Nonproducing Reservoirs (Million Barrels) Decade Year-0 Year-1 Year-2 Year-3 Year-4 Year-5 Year-6 Year-7 Year-8 Year-9 1990's NA NA 26 30 2000's 49 44 56 61 62 74 102 122 123 42 2010's 180 208 283 607 765 - = No Data Reported; -- = Not Applicable; NA = Not Available; W = Withheld to avoid disclosure of individual company data. Release Date: 11/19/2015 Next Release Date: 12/31/2016 Referring Pages: Proved

  9. Florida Crude Oil Reserves in Nonproducing Reservoirs (Million Barrels)

    U.S. Energy Information Administration (EIA) Indexed Site

    Reserves in Nonproducing Reservoirs (Million Barrels) Florida Crude Oil Reserves in Nonproducing Reservoirs (Million Barrels) Decade Year-0 Year-1 Year-2 Year-3 Year-4 Year-5 Year-6 Year-7 Year-8 Year-9 1990's NA NA 6 12 2000's 9 7 7 6 6 2 1 12 0 2 2010's 2 4 3 9 6 - = No Data Reported; -- = Not Applicable; NA = Not Available; W = Withheld to avoid disclosure of individual company data. Release Date: 11/19/2015 Next Release Date: 12/31/2016 Referring Pages: Proved Nonproducing Reserves of Crude

  10. Kansas Crude Oil Reserves in Nonproducing Reservoirs (Million Barrels)

    U.S. Energy Information Administration (EIA) Indexed Site

    Reserves in Nonproducing Reservoirs (Million Barrels) Kansas Crude Oil Reserves in Nonproducing Reservoirs (Million Barrels) Decade Year-0 Year-1 Year-2 Year-3 Year-4 Year-5 Year-6 Year-7 Year-8 Year-9 1990's NA NA 11 12 2000's 13 21 23 18 11 16 17 9 11 3 2010's 2 4 6 11 34 - = No Data Reported; -- = Not Applicable; NA = Not Available; W = Withheld to avoid disclosure of individual company data. Release Date: 11/19/2015 Next Release Date: 12/31/2016 Referring Pages: Proved Nonproducing Reserves

  11. Kentucky Crude Oil Reserves in Nonproducing Reservoirs (Million Barrels)

    U.S. Energy Information Administration (EIA) Indexed Site

    Reserves in Nonproducing Reservoirs (Million Barrels) Kentucky Crude Oil Reserves in Nonproducing Reservoirs (Million Barrels) Decade Year-0 Year-1 Year-2 Year-3 Year-4 Year-5 Year-6 Year-7 Year-8 Year-9 1990's NA NA 0 0 2000's 0 0 4 4 5 5 0 0 1 3 2010's 0 0 0 1 0 - = No Data Reported; -- = Not Applicable; NA = Not Available; W = Withheld to avoid disclosure of individual company data. Release Date: 11/19/2015 Next Release Date: 12/31/2016 Referring Pages: Proved Nonproducing Reserves of Crude

  12. Utah Crude Oil Reserves in Nonproducing Reservoirs (Million Barrels)

    U.S. Energy Information Administration (EIA) Indexed Site

    Reserves in Nonproducing Reservoirs (Million Barrels) Utah Crude Oil Reserves in Nonproducing Reservoirs (Million Barrels) Decade Year-0 Year-1 Year-2 Year-3 Year-4 Year-5 Year-6 Year-7 Year-8 Year-9 1990's NA NA 36 58 2000's 91 100 91 76 61 52 164 174 140 235 2010's 257 258 368 312 261 - = No Data Reported; -- = Not Applicable; NA = Not Available; W = Withheld to avoid disclosure of individual company data. Release Date: 11/19/2015 Next Release Date: 12/31/2016 Referring Pages: Proved

  13. West Virginia Crude Oil Reserves in Nonproducing Reservoirs (Million

    U.S. Energy Information Administration (EIA) Indexed Site

    Barrels) Reserves in Nonproducing Reservoirs (Million Barrels) West Virginia Crude Oil Reserves in Nonproducing Reservoirs (Million Barrels) Decade Year-0 Year-1 Year-2 Year-3 Year-4 Year-5 Year-6 Year-7 Year-8 Year-9 1990's NA NA 3 3 2000's 0 0 0 0 0 0 0 0 0 0 2010's 0 1 1 2 1 - = No Data Reported; -- = Not Applicable; NA = Not Available; W = Withheld to avoid disclosure of individual company data. Release Date: 11/19/2015 Next Release Date: 12/31/2016 Referring Pages: Proved Nonproducing

  14. Wyoming Crude Oil Reserves in Nonproducing Reservoirs (Million Barrels)

    U.S. Energy Information Administration (EIA) Indexed Site

    Reserves in Nonproducing Reservoirs (Million Barrels) Wyoming Crude Oil Reserves in Nonproducing Reservoirs (Million Barrels) Decade Year-0 Year-1 Year-2 Year-3 Year-4 Year-5 Year-6 Year-7 Year-8 Year-9 1990's NA NA 31 52 2000's 63 74 69 61 45 249 258 208 162 144 2010's 152 188 233 219 362 - = No Data Reported; -- = Not Applicable; NA = Not Available; W = Withheld to avoid disclosure of individual company data. Release Date: 11/19/2015 Next Release Date: 12/31/2016 Referring Pages: Proved

  15. Process for stimulating and upgrading the oil production from a heavy oil reservoir

    SciTech Connect (OSTI)

    Sweany, G.A.

    1981-08-18

    A process for thermally stimulating and upgrading oil production from a heavy oil reservoir wherein the heavy oil produced from the reservoir is combined with a hydrogen donor diluent and the mixture is subjected to thermal cracking to upgrade the heavy oil into more valuable hydrocarbon products. The cracked products are fractionated into a light end vapor fraction, an intermediate liquid fraction, a gas oil fraction and a pitch fraction, and at least a portion of the gas oil fraction is hydrogenated by contacting it with a hydrogen-containing gas stream to produce the hydrogen donor diluent combined with the heavy oil. The pitch fraction is subjected to partial oxidation to produce the hydrogen-containing gas stream and a by-product gas stream containing steam which is combined with additional steam and injected into the heavy oil reservoir to enhance the mobility of heavy oil contained therein. The light end vapor fraction and unreacted hydrogen-containing gas produced by the process are utilized as fuel in the process. The intermediate liquid fraction produce and portion of the gas oil fraction not hydrogenated are readily transportable from the process.

  16. Evaluation of Reservoir Wettability and its Effect on Oil Recovery

    SciTech Connect (OSTI)

    Buckley, Jill S.

    1999-11-09

    This project has three main goals. The first is to achieve improved understanding of the surface and interfacial properties of crude oils and their interactions with mineral surfaces. The second goal is to apply the results of surface studies to improved predictions of oil production in laboratory experiments. Finally, we aim to use the results of this research to recommend ways to improve oil recovery by waterflooding. In order to achieve these goals, the mechanisms of wetting alteration must be explained. We propose a methodology for studying those mechanisms on mineral surfaces, then applying the results to prediction and observation of wetting alteration in porous media. Improved understanding of the underlying mechanisms will show when and how wettability in the reservoir can be altered and under what circumstances that alteration would be beneficial in terms of increased production of oil.

  17. Evaluation of Reservoir Wettability and its Effect on Oil Recovery

    SciTech Connect (OSTI)

    Jill S. Buckley

    1998-04-13

    This project has three main goals. The first is to achieve improved understanding of the surface and interfacial properties of crude oils and their interactions with mineral surfaces. The second goal is to apply the results of surface studies to improved predictions of oil production in laboratory experiments. Finally, we aim to use the results of this research to recommend ways to improve oil recovery by waterflooding. In order to achieve these goals, the mechanisms of wetting alteration must be explained. We propose a methodology for studying those mechanisms on mineral surfaces, then applying the results to prediction and observation of wetting alteration in porous media. Improved understanding of the underlying mechanisms will show when and how wettability in the reservoir can be altered and under what circumstances that alteration would be beneficial in terms of increased production of oil.

  18. Nebraska Crude Oil Reserves in Nonproducing Reservoirs (Million Barrels)

    U.S. Energy Information Administration (EIA) Indexed Site

    Crude Oil Reserves in Nonproducing Reservoirs (Million Barrels) Decade Year-0 Year-1 Year-2 Year-3 Year-4 Year-5 Year-6 Year-7 Year-8 Year-9 1990's NA NA 0 0 2000's 0 0 0 0 0 - = No Data Reported; -- = Not Applicable; NA = Not Available; W = Withheld to avoid disclosure of individual company data. Release Date: 11/19/2015 Next Release Date: 12/31/2016 Referring Pages: Proved Nonproducing Reserves of Crude Oil Nebraska Proved Nonproducing Reserves

  19. New York Crude Oil Reserves in Nonproducing Reservoirs (Million Barrels)

    U.S. Energy Information Administration (EIA) Indexed Site

    Crude Oil Reserves in Nonproducing Reservoirs (Million Barrels) Decade Year-0 Year-1 Year-2 Year-3 Year-4 Year-5 Year-6 Year-7 Year-8 Year-9 1990's NA NA 0 0 2000's 0 0 0 0 0 0 0 0 0 0 2010's 0 0 0 0 0 - = No Data Reported; -- = Not Applicable; NA = Not Available; W = Withheld to avoid disclosure of individual company data. Release Date: 11/19/2015 Next Release Date: 12/31/2016 Referring Pages: Proved Nonproducing Reserves of Crude Oil New York Proved Nonproducing Reserves

  20. Indiana Crude Oil Reserves in Nonproducing Reservoirs (Million Barrels)

    U.S. Energy Information Administration (EIA) Indexed Site

    Indiana Crude Oil Reserves in Nonproducing Reservoirs (Million Barrels) Decade Year-0 Year-1 Year-2 Year-3 Year-4 Year-5 Year-6 Year-7 Year-8 Year-9 1990's NA NA 0 0 2000's 0 0 0 0 0 0 - = No Data Reported; -- = Not Applicable; NA = Not Available; W = Withheld to avoid disclosure of individual company data. Release Date: 11/19/2015 Next Release Date: 12/31/2016 Referring Pages: Proved Nonproducing Reserves of Crude Oil Indiana Proved Nonproducing Reserves

  1. Increasing Waterflood Reserves in the Wilmington Oil Field Through Improved Reservoir Characterization and Reservoir Management.

    SciTech Connect (OSTI)

    Koerner, R.; Clarke, D.; Walker, S.; Phillips, C.; Nguyen, J.; Moos, D.; Tagbor, K.

    1997-10-21

    The objectives of this quarterly report are to summarize the work conducted under each task during the reporting period July - September 1997 and to report all technical data and findings as specified in the `Federal Assistance Reporting Checklist`. The main objective of this project is the transfer of technologies, methodologies, and findings developed and applied in this project to other operators of Slope and Basin Clastic Reservoirs. This project will study methods to identify sands with high remaining oil saturation and to recomplete existing wells using advanced completion technology. The identification of the sands with high remaining oil saturation will be accomplished by developing a deterministic three dimensional (3-D) geologic model and by using a state of the art reservoir management computer software. The wells identified by the geologic and reservoir engineering work as having the best potential will be logged with a pulsed acoustic cased-hole logging tool. The application of the logging tools will be optimized in the lab by developing a rock-log model. This rock-log model will allow us to convert shear wave velocity measured through casing into effective porosity and hydrocarbon saturation. The wells that are shown to have the best oil production potential will be recompleted. The recompletions will be optimized by evaluating short radius and ultra-short radius lateral recompletions as well as other techniques.

  2. Increasing Waterflood Reserves in the Wilmington Oil Field Through Improved Reservoir Characterization and Reservoir Management

    SciTech Connect (OSTI)

    Chris Phillips; Dan Moos; Don Clarke; John Nguyen; Kwasi Tagbor; Roy Koerner; Scott Walker.

    1998-01-26

    The objectives of this quarterly report are to summarize the work conducted under each task during the reporting period October - December 1997 and to report all technical data and findings as specified in the Federal Assistance Reporting Checklist . The main objective of this project is the transfer of technologies, methodologies, and findings developed and applied in this project to other operators of Slope and Basin Clastic Reservoirs. This project will study methods to identify sands with high remaining oil saturation and to recomplete existing wells using advanced completion technology. The identification of the sands with high remaining oil saturation will be accomplished by developing a deterministic three dimensional (3-D) geologic model and by using a state of the art reservoir management computer software. The wells identified by the geologic and reservoir engineering work as having the best potential will be logged with cased-hole logging tools. The application of the logging tools will be optimized in the lab by developing a rock-log model. This rock-log model will allow us to translate measurements through casing into effective porosity and hydrocarbon saturation. The wells that are shown to have the best oil production potential will be recompleted. The recompletions will be optimized by evaluating short radius lateral recompletions as well as other recompletion techniques such as the sand consolidation through steam injection.

  3. Increasing Waterflood Reserves in the Wilmington Oil Field Through Improved Reservoir Characterization and Reservoir Management

    SciTech Connect (OSTI)

    Chris Phillips; Dan Moos; Don Clarke; John Nguyen; Kwasi Tagbor; Roy Koerner; Scott Walker

    1998-04-22

    The objectives of this quarterly report are to summarize the work conducted under each task during the reporting period January - March 1998 and to report all technical data and findings as specified in the "Federal Assistance Reporting Checklist". The main objective of this project is the transfer of technologies, methodologies, and findings developed and applied in this project to other operators of Slope and Basin Clastic Reservoirs. This project will study methods to identify sands with high remaining oil saturation and to recomplete existing wells using advanced completion technology. The identification of the sands with high remaining oil saturation will be accomplished by developing a deterministic three dimensional (3-D) geologic model and by using a state of the art reservoir management computer software. The wells identified by the geologic and reservoir engineering work as having the best potential will be logged with cased-hole logging tools. The application of the logging tools will be optimized in the lab by developing a rock-log model. This rock-log model will allow us to translate measurements through casing into effective porosity and hydrocarbon saturation. The wells that are shown to have the best oil production potential will be recompleted. The recompletions will be optimized by evaluating short radius lateral recompletions as well as other recompletion techniques such as the sand consolidation through steam injection.

  4. Increasing Waterflood Reserves in the Wilmington Oil Field Through Improved Reservoir Characterization and Reservoir Management.

    SciTech Connect (OSTI)

    Koerner, Roy; Clarke, Don; Walker, Scott; Phillips, Chris; Nauyen, John; Moos, Dan; Tagbor, Kwasi

    1997-07-28

    The objectives of this quarterly report are to summarize the work conducted under each task during the reporting period April - June 1997 and to report all technical data and findings as specified in the `Federal Assistance Reporting Checklist`. The main objective of this project is the transfer of technologies, methodologies, and findings developed and applied in this project to other operators of Slope and Basin Clastic Reservoirs. This project will study methods to identify sands with high remaining oil saturation and to recomplete existing wells using advanced completion technology. The identification of the sands with high remaining oil saturation will be accomplished by developing a deterministic three dimensional (3-D) geologic model and by using a state of the art reservoir management computer software. The wells identified by the geologic and reservoir engineering work as having the best potential will be logged with a pulsed acoustic cased-hole logging tool. The application of the logging tools will be optimized in the lab by developing a rock-log model. This rock-log model will allow us to convert shear wave velocity measured through casing into effective porosity and hydrocarbon saturation. The wells that are shown to have the best oil production potential will be recompleted. The recompletions will be optimized by evaluating short radius and ultra-short radius lateral recompletions as well as other techniques.

  5. Increasing Waterflood Reserves in the Wilmington Oil Field Through Improved Reservoir Characterization and Reservoir Management

    SciTech Connect (OSTI)

    Chris Phillips; Dan Moos; Don Clarke; John Nguyen; Kwasi Tagbor; Roy Koerner; Scott Walker

    1998-01-26

    The objectives of this quarterly report are to summarize the work conducted under each task during the reporting period October - December 1997 and to report all technical data and findings as specified in the "Federal Assistance Reporting Checklist". The main objective of this project is the transfer of technologies, methodologies, and findings developed and applied in this project to other operators of Slope and Basin Clastic Reservoirs. This project will study methods to identify sands with high remaining oil saturation and to recomplete existing wells using advanced completion technology. The identification of the sands with high remaining oil saturation will be accomplished by developing a deterministic three dimensional (3-D) geologic model and by using a state of the art reservoir management computer software. The wells identified by the geologic and reservoir engineering work as having the best potential will be logged with cased-hole logging tools. The application of the logging tools will be optimized in the lab by developing a rock-log model. This rock-log model will allow us to translate measurements through casing into effective porosity and hydrocarbon saturation. The wells that are shown to have the best oil production potential will be recompleted. The recompletions will be optimized by evaluating short radius lateral recompletions as well as other recompletion techniques such as the sand consolidation through steam injection.

  6. Producing Light Oil from a Frozen Reservoir: Reservoir and Fluid Characterization of Umiat Field, National Petroleum Reserve, Alaska

    SciTech Connect (OSTI)

    Hanks, Catherine

    2012-12-31

    Umiat oil field is a light oil in a shallow, frozen reservoir in the Brooks Range foothills of northern Alaska with estimated oil-in-place of over 1 billion barrels. Umiat field was discovered in the 1940’s but was never considered viable because it is shallow, in the permafrost, and far from any transportation infrastructure. The advent of modern drilling and production techniques has made Umiat and similar fields in northern Alaska attractive exploration and production targets. Since 2008 UAF has been working with Renaissance Alaska Inc. and, more recently, Linc Energy, to develop a more robust reservoir model that can be combined with rock and fluid property data to simulate potential production techniques. This work will be used to by Linc Energy as they prepare to drill up to 5 horizontal wells during the 2012-2013 drilling season. This new work identified three potential reservoir horizons within the Cretaceous Nanushuk Formation: the Upper and Lower Grandstand sands, and the overlying Ninuluk sand, with the Lower Grandstand considered the primary target. Seals are provided by thick interlayered shales. Reserve estimates for the Lower Grandstand alone range from 739 million barrels to 2437 million barrels, with an average of 1527 million bbls. Reservoir simulations predict that cold gas injection from a wagon-wheel pattern of multilateral injectors and producers located on 5 drill sites on the crest of the structure will yield 12-15% recovery, with actual recovery depending upon the injection pressure used, the actual Kv/Kh encountered, and other geologic factors. Key to understanding the flow behavior of the Umiat reservoir is determining the permeability structure of the sands. Sandstones of the Cretaceous Nanushuk Formation consist of mixed shoreface and deltaic sandstones and mudstones. A core-based study of the sedimentary facies of these sands combined with outcrop observations identified six distinct facies associations with distinctive permeability trends. The Lower Grandstand sand consists of two coarsening-upward shoreface sands sequences while the Upper Grandstand consists of a single coarsening-upward shoreface sand. Each of the shoreface sands shows a distinctive permeability profile with high horizontal permeability at the top getting progressively poorer towards the base of the sand. In contrast, deltaic sandstones in the overlying Ninuluk are more permeable at the base of the sands, with decreasing permeability towards the sand top. These trends impart a strong permeability anisotropy to the reservoir and are being incorporated into the reservoir model. These observations also suggest that horizontal wells should target the upper part of the major sands. Natural fractures may superimpose another permeability pattern on the Umiat reservoir that need to be accounted for in both the simulation and in drilling. Examination of legacy core from Umiat field indicate that fractures are present in the subsurface, but don't provide information on their orientation and density. Nearby surface exposures of folds in similar stratigraphy indicate there are at least three possible fracture sets: an early, N/S striking set that may predate folding and two sets possibly related to folding: an EW striking set of extension fractures that are parallel to the fold axes and a set of conjugate shear fractures oriented NE and NW. Analysis of fracture spacing suggests that these natural fractures are fairly widely spaced (25-59 cm depending upon the fracture set), but could provide improved reservoir permeability in horizontal legs drilled perpendicular to the open fracture set. The phase behavior of the Umiat fluid needed to be well understood in order for the reservoir simulation to be accurate. However, only a small amount of Umiat oil was available; this oil was collected in the 1940’s and was severely weathered. The composition of this ‘dead’ Umiat fluid was characterized by gas chromatography. This analysis was then compared to theoretical Umiat composition derived using the Pedersen method with original Umiat fluid properties published in the original reports. This comparison allowed estimation of the ‘lost’ light hydrocarbon fractions. An Umiat 'dead' oil sample then could be physically created by adding the lost light ends to the weatherized Umiat dead oil sample. This recreated sample was recombined with solution gas to create a 'pseudo-live' Umiat oil sample which was then used for experimental PVT and phase behavior studies to determine fluid properties over the range of reservoir pressures and temperatures. The phase behavior of the ‘pseudo-live’ oil was also simulated using the Peng- Robinson equations of state (EOS). The EOS model was tuned with measured experimental data to accurately simulate the differential liberation tests in order to obtain the necessary data for reservoir simulation studies, including bubble point pressure and oil viscosity. The bubble point pressure of the reconstructed Umiat oil is 345 psi, suggesting that maintenance of reservoir pressures above that pressure will be important for the any proposed production technique. A major part of predicting how the Umiat reservoir will perform is determining the relative permeability of oil in the presence of ice. Early in the project, UAF work on samples of the Umiat reservoir indicated that there is a significant reduction in the relatively permeability of oil in the presence of ice. However, it was not clear as to why this reduction occurred or where the ice resided. To explore this further, additional experimental and theoretical work was conducted. Core flood experiments were performed on two clean Berea sandstone cores under permafrost conditions to determine the relative permeability to oil (kro) over a temperature range of 23ºC to - 10ºC and for a range of connate water salinities. Both cores showed maximum reduction in relative permeability to oil when saturated with deionized water and less reduction when saturated with saline water. This reduction in relative permeability can be explained by formation of ice crystals in the center of pores. Theoretically, the radius of ice formed in the center of the pore can be determined using the Kozeny–Carman Equation by assuming the pores and pore throats as a cube with ‘N’ identical parallel pipes embedded in it. Using the values of kro obtained from the experimental work as input to the Kozeny–Carman Equation at -10ºC, the radius of ice crystals dropped from 0.145 μm to 0.069 μm when flooding-water salinity is increased to 6467 ppm. This explains the reduction of relative permeability with decreasing salinity but does not take into consideration other effects such as variations in pore throat structure. In addition, fluids like deionized water, saline water, and antifreeze (a mixture of 60% ethylene or propylene glycol with 40% water) were tested to find the best flooding agent for frozen reservoirs. At 0ºC, 9% greater recovery was observed with antifreeze was used as a flooding agent as compared to using saline water. Antifreeze showed 48% recovery even at -10ºC, at which temperature the rest of the fluids failed to increase production. Preliminary evaluation of drilling fluids indicate that the brine-based muds caused significantly less swelling in the Umiat reservoir sands when compared to fresh-water based muds. However since freezing filtrate is another cause of formation damage, a simple water-based-mud may not a viable option. It is recommended that new fluids be tested, including different salts, brines, polymers and oil-based fluids. These fluids should be tested at low temperatures in order to determine the potential for formation damage, the fluid properties under these conditions and to ensure that the freezing point is below that of the reservoir. In order to reduce the surface footprint while accessing the maximum amount of the Lower Grandstand interval, simulations used development from 5 surface locations with a wagon-wheel pattern of multilateral injectors and producers. There is no active aquifer support due to small peizometric head in the area and no existing gas cap, so an alternative method of pressure support is needed. Cold gas injection was used in the simulations as it is considered the most viable means of providing pressure maintenance while maintaining wellbore stability and reducing impact on the permafrost. Saline water injection may be a viable alternative, though this may have a detrimental effect on permafrost. In the short term, the results of this work are being incorporated into Linc Energy’s drilling and development plan. This project has also provided valuable information on the rock and fluid properties of low temperature reservoirs as well as the efficacy of potential production techniques for Umiat or similar shallow frozen reservoirs in the circum-Arctic.

  7. IMPROVING CO2 EFFICIENCY FOR RECOVERING OIL IN HETEROGENEOUS RESERVOIRS

    SciTech Connect (OSTI)

    Reid B. Grigg; Robert K. Svec

    2002-12-20

    This document is the First Annual Report for the U.S. Department of Energy under contract No., a three-year contract entitled: ''Improving CO{sub 2} Efficiency for Recovering Oil in Heterogeneous Reservoirs.'' The research improved our knowledge and understanding of CO{sub 2} flooding and includes work in the areas of injectivity and mobility control. The bulk of this work has been performed by the New Mexico Petroleum Recovery Research Center, a research division of New Mexico Institute of Mining and Technology. This report covers the reporting period of September 28, 2001 and September 27, 2002. Injectivity continues to be a concern to the industry. During this period we have contacted most of the CO{sub 2} operators in the Permian Basin and talked again about their problems in this area. This report has a summary of what we found. It is a given that carbonate mineral dissolution and deposition occur in a formation in geologic time and are expected to some degree in carbon dioxide (CO{sub 2}) floods. Water-alternating-gas (WAG) core flood experiments conducted on limestone and dolomite core plugs confirm that these processes can occur over relatively short time periods (hours to days) and in close proximity to each other. Results from laboratory CO{sub 2}-brine flow experiments performed in rock core were used to calibrate a reactive transport simulator. The calibrated model is being used to estimate in situ effects of a range of possible sequestration options in depleted oil/gas reservoirs. The code applied in this study is a combination of the well known TOUGH2 simulator, for coupled groundwater/brine and heat flow, with the chemistry code TRANS for chemically reactive transport. Variability in response among rock types suggests that CO{sub 2} injection will induce ranges of transient and spatially dependent changes in intrinsic rock permeability and porosity. Determining the effect of matrix changes on CO{sub 2} mobility is crucial in evaluating the efficacy and potential environmental implications of storing CO{sub 2} in the subsurface. Chemical cost reductions are identified that are derived from the synergistic effects of cosurfactant systems using a good foaming agent and a less expensive poor foaming agent. The required good foaming agent is reduced by at least 75%. Also the effect on injectivity is reduced by as much as 50% using the cosurfactant system, compared to a previously used surfactant system. Mobility control of injected CO{sub 2} for improved oil recovery can be achieved with significant reduction in the chemical cost of SAG, improved injectivity of SAG, and improved economics of CO{sub 2} injection project when compared to reported systems. Our past work has identified a number of mobility control agents to use for CO{sub 2}-foam flooding. In particular the combination of the good foaming agent CD 1045 and a sacrificial agent and cosurfactant lignosulfonate. This work scrutinizes the methods that we are using to determine the efficiency of the sacrificial agents and cosurfactant systems. These have required concentration determinations and reusing core samples. Here, we report some of the problems that have been found and some interesting effects that must be considered.

  8. Lower 48 States Crude Oil Reserves in Nonproducing Reservoirs (Million

    U.S. Energy Information Administration (EIA) Indexed Site

    Barrels) Reserves in Nonproducing Reservoirs (Million Barrels) Lower 48 States Crude Oil Reserves in Nonproducing Reservoirs (Million Barrels) Decade Year-0 Year-1 Year-2 Year-3 Year-4 Year-5 Year-6 Year-7 Year-8 Year-9 1990's NA NA 3,341 3,274 2000's 3,508 4,806 4,725 4,846 4,436 5,096 4,732 5,055 4,871 5,382 2010's 6,358 8,483 11,082 12,561 14,268 - = No Data Reported; -- = Not Applicable; NA = Not Available; W = Withheld to avoid disclosure of individual company data. Release Date:

  9. Increasing Waterflood Reserves in the Wilmington Oil Field Through Improved Reservoir Characterization and Reservoir Management

    SciTech Connect (OSTI)

    Chris Phillips; Dan Moos; Don Clarke; Dwasi Tagbor; John Nguygen; Roy Koerner; Scott Walker

    1997-04-10

    The objectives of this quarterly report are to summarize the work conducted under each task during the reporting period January - March 1997 and to report all technical data and findings as specified in the "Federal Assistance Reporting Checklist". The main objective of this project is the transfer of technologies, methodologies, and findings developed and applied in this project to other operators of Slope and Basin Clastic Reservoirs. This project will study methods to identify sands with high remaining oil saturation and to recomplete existing wells using advanced completion technology.

  10. USE OF POLYMERS TO RECOVER VISCOUS OIL FROM UNCONVENTIONAL RESERVOIRS

    SciTech Connect (OSTI)

    Randall Seright

    2011-09-30

    This final technical progress report summarizes work performed the project, 'Use of Polymers to Recover Viscous Oil from Unconventional Reservoirs.' The objective of this three-year research project was to develop methods using water soluble polymers to recover viscous oil from unconventional reservoirs (i.e., on Alaska's North Slope). The project had three technical tasks. First, limits were re-examined and redefined for where polymer flooding technology can be applied with respect to unfavorable displacements. Second, we tested existing and new polymers for effective polymer flooding of viscous oil, and we tested newly proposed mechanisms for oil displacement by polymer solutions. Third, we examined novel methods of using polymer gels to improve sweep efficiency during recovery of unconventional viscous oil. This report details work performed during the project. First, using fractional flow calculations, we examined the potential of polymer flooding for recovering viscous oils when the polymer is able to reduce the residual oil saturation to a value less than that of a waterflood. Second, we extensively investigated the rheology in porous media for a new hydrophobic associative polymer. Third, using simulation and analytical studies, we compared oil recovery efficiency for polymer flooding versus in-depth profile modification (i.e., 'Bright Water') as a function of (1) permeability contrast, (2) relative zone thickness, (3) oil viscosity, (4) polymer solution viscosity, (5) polymer or blocking-agent bank size, and (6) relative costs for polymer versus blocking agent. Fourth, we experimentally established how much polymer flooding can reduce the residual oil saturation in an oil-wet core that is saturated with viscous North Slope crude. Finally, an experimental study compared mechanical degradation of an associative polymer with that of a partially hydrolyzed polyacrylamide. Detailed results from the first two years of the project may be found in our first and second annual reports. Our latest research results, along with detailed documentation of our past work, can be found on our web site at http://baervan.nmt.edu/randy/. As an overall summary of important findings for the project, polymer flooding has tremendous potential for enhanced recovery of viscous oil. Fear of substantial injectivity reduction was a primary hurdle that limited application of polymer flooding. However, that concern is largely mitigated by (1) use of horizontal wells and (2) judicious injection above the formation parting pressure. Field cases now exist where 200-300-cp polymer solutions are injected without significant reductions in injectivity. Concern about costs associated with injection of viscous polymer solutions was a second major hurdle. However, that concern is reduced substantially by realization that polymer viscosity increases approximately with the square of polymer concentration. Viscosity can be doubled with only a 40% increase in polymer concentration. Up to a readily definable point, increases in viscosity of the injected polymer solution are directly related to increases in sweep efficiency and oil recovery. Previously published simulation results - suggesting that shear-thinning polymer solutions were detrimental to sweep efficiency - were shown to be unfounded (both theoretically and experimentally).

  11. Improved Oil Recovery in Fluvial Dominated Deltaic Reservoirs of Kansas - Near-Term

    SciTech Connect (OSTI)

    A. Walton; D. McCune; D.W. Green; G.P. Willhite; L. Watney; M. Michnick; R. Reynolds

    1997-10-15

    The objective of this study is to study waterflood problems of the type found in Morrow sandstone. The major tasks undertaken are reservoir characterization and the development of a reservoir database; volumetric analysis to evaluate production performance; reservoir modeling; identification of operational problems; identification of unrecovered mobile oil and estimation of recovery factors; and identification of the most efficient and economical recovery process.

  12. Improved Oil Recovery in Fluvial Dominated Deltaic Reservoirs of Kansas - Near-Term

    SciTech Connect (OSTI)

    A. Walton; D. McCune; D.W. Green; G.P. Willhite; L. Watney; M. Cichnick; R. Reynolds

    1998-07-15

    The objective of this study is to study waterflood problems of the type found in Morrow sandstone. The major tasks undertaken are reservoir characterization and the development of a reservoir database; volumetric analysis to evaluate production performance; reservoir modeling; identification of operational problems; identification of unrecovered mobile oil and estimation of recovery factors; and identification of the most efficient and economical recovery process.

  13. Improved Oil Recovery in Fluvial Dominated Deltaic Reservoirs of Kansas - Near-Term

    SciTech Connect (OSTI)

    A. Walton; D. McCune; D.W. Green; G.P. Willhite; L. Watney; R. Reynolds; m. Michnick

    1998-04-15

    The objective of this study is to study waterflood problems of the type found in Morrow sandstone. The major tasks undertaken are reservoir characterization and the development of a reservoir database; volumetric analysis to evaluate production performance; reservoir modeling; identification of operational problems; identification of unrecovered mobile oil and estimation of recovery factors; and identification of the most efficient and economical recovery process.

  14. Increasing Heavy Oil Reserves in the Wilmington Oil Field Through Advanced Reservoir Characterization and Thermal Production Technologies, Class III

    SciTech Connect (OSTI)

    City of Long Beach; Tidelands Oil Production Company; University of Southern California; David K. Davies and Associates

    2002-09-30

    The objective of this project was to increase the recoverable heavy oil reserves within sections of the Wilmington Oil Field, near Long Beach, California through the testing and application of advanced reservoir characterization and thermal production technologies. It was hoped that the successful application of these technologies would result in their implementation throughout the Wilmington Field and, through technology transfer, will be extended to increase the recoverable oil reserves in other slope and basin clastic (SBC) reservoirs.

  15. RESERVOIR CHARACTERIZATION OF UPPER DEVONIAN GORDON SANDSTONE, JACKSONBURG STRINGTOWN OIL FIELD, NORTHWESTERN WEST VIRGINIA

    SciTech Connect (OSTI)

    S. Ameri; K. Aminian; K.L. Avary; H.I. Bilgesu; M.E. Hohn; R.R. McDowell; D.L. Matchen

    2001-07-01

    The Jacksonburg-Stringtown oil field contained an estimated 88,500,000 barrels of oil in place, of which approximately 20,000,000 barrels were produced during primary recovery operations. A gas injection project, initiated in 1934, and a pilot waterflood, begun in 1981, yielded additional production from limited portions of the field. The pilot was successful enough to warrant development of a full-scale waterflood in 1990, involving approximately 8,900 acres in three units, with a target of 1,500 barrels of oil per acre recovery. Historical patterns of drilling and development within the field suggests that the Gordon reservoir is heterogeneous, and that detailed reservoir characterization is necessary for understanding well performance and addressing problems observed by the operators. The purpose of this work is to establish relationships among permeability, geophysical and other data by integrating geologic, geophysical and engineering data into an interdisciplinary quantification of reservoir heterogeneity as it relates to production. Conventional stratigraphic correlation and core description shows that the Gordon sandstone is composed of three parasequences, formed along the Late Devonian shoreline of the Appalachian Basin. The parasequences comprise five lithofacies, of which one includes reservoir sandstones. Pay sandstones were found to have permeabilities in core ranging from 10 to 200 mD, whereas non-pay sandstones have permeabilities ranging from below the level of instrumental detection to 5 mD; Conglomeratic zones could take on the permeability characteristics of enclosing materials, or could exhibit extremely low values in pay sandstone and high values in non-pay or low permeability pay sandstone. Four electrofacies based on a linear combination of density and scaled gamma ray best matched correlations made independently based on visual comparison of geophysical logs. Electrofacies 4 with relatively high permeability (mean value > 45 mD) was determined to be equivalent to the pay sandstone within the Gordon reservoir. Three-dimensional models of the electrofacies in the pilot waterflood showed that electrofacies 4 is present throughout this area, and the other electrofacies are more disconnected. A three-layer, back-propagation artificial neural network with three slabs in the middle layer can be used to predict permeability and porosity from gamma ray and bulk density logs, the first and the second derivatives of the log data with respect to depth, well location, and log baselines. Two flow units were defined based on the stratigraphic model and geophysical logs. A three-dimensional reservoir model including the flow units, values of permeability calculated through the artificial neural network and injection pressure-rate information were then used as inputs for a reservoir simulator to predict oil production performance for the center producers in the pilot area. This description of the reservoir provided significantly better simulation results than earlier results obtained using simple reservoir models. Bulk density and gamma ray logs were used to identify flow units throughout the field. As predicted by the stratigraphic analysis, one of the flow units crosses stratigraphic units in the reservoir. A neural network was used to predict permeability values for each flow unit in producer and injection wells. The reservoir simulator was utilized to predict the performance of two flood patterns located to the north of the pilot area. Considering the simple model utilized for simulation, the results are in very good agreement with the field history.

  16. Characterization of oil and gas reservoirs and recovery technology deployment on Texas State Lands

    SciTech Connect (OSTI)

    Tyler, R.; Major, R.P.; Holtz, M.H.

    1997-08-01

    Texas State Lands oil and gas resources are estimated at 1.6 BSTB of remaining mobile oil, 2.1 BSTB, or residual oil, and nearly 10 Tcf of remaining gas. An integrated, detailed geologic and engineering characterization of Texas State Lands has created quantitative descriptions of the oil and gas reservoirs, resulting in delineation of untapped, bypassed compartments and zones of remaining oil and gas. On Texas State Lands, the knowledge gained from such interpretative, quantitative reservoir descriptions has been the basis for designing optimized recovery strategies, including well deepening, recompletions, workovers, targeted infill drilling, injection profile modification, and waterflood optimization. The State of Texas Advanced Resource Recovery program is currently evaluating oil and gas fields along the Gulf Coast (South Copano Bay and Umbrella Point fields) and in the Permian Basin (Keystone East, Ozona, Geraldine Ford and Ford West fields). The program is grounded in advanced reservoir characterization techniques that define the residence of unrecovered oil and gas remaining in select State Land reservoirs. Integral to the program is collaboration with operators in order to deploy advanced reservoir exploitation and management plans. These plans are made on the basis of a thorough understanding of internal reservoir architecture and its controls on remaining oil and gas distribution. Continued accurate, detailed Texas State Lands reservoir description and characterization will ensure deployment of the most current and economically viable recovery technologies and strategies available.

  17. Study on detailed geological modelling for fluvial sandstone reservoir in Daqing oil field

    SciTech Connect (OSTI)

    Zhao Hanqing; Fu Zhiguo; Lu Xiaoguang

    1997-08-01

    Guided by the sedimentation theory and knowledge of modern and ancient fluvial deposition and utilizing the abundant information of sedimentary series, microfacies type and petrophysical parameters from well logging curves of close spaced thousands of wells located in a large area. A new method for establishing detailed sedimentation and permeability distribution models for fluvial reservoirs have been developed successfully. This study aimed at the geometry and internal architecture of sandbodies, in accordance to their hierarchical levels of heterogeneity and building up sedimentation and permeability distribution models of fluvial reservoirs, describing the reservoir heterogeneity on the light of the river sedimentary rules. The results and methods obtained in outcrop and modem sedimentation studies have successfully supported the study. Taking advantage of this method, the major producing layers (PI{sub 1-2}), which have been considered as heterogeneous and thick fluvial reservoirs extending widely in lateral are researched in detail. These layers are subdivided into single sedimentary units vertically and the microfacies are identified horizontally. Furthermore, a complex system is recognized according to their hierarchical levels from large to small, meander belt, single channel sandbody, meander scroll, point bar, and lateral accretion bodies of point bar. The achieved results improved the description of areal distribution of point bar sandbodies, provide an accurate and detailed framework model for establishing high resolution predicting model. By using geostatistic technique, it also plays an important role in searching for enriched zone of residual oil distribution.

  18. Increasing Heavy Oil Reserves in the Wilmington Oil Field Through Advanced Reservoir Characterization and Thermal Production Technologies, Class III

    SciTech Connect (OSTI)

    City of Long Beach; Tidelands Oil Production Company; University of Southern California; David K. Davies and Associates

    2002-09-30

    The objective of this project was to increase the recoverable heavy oil reserves within sections of the Wilmington Oil Field, near Long Beach, California through the testing and application of advanced reservoir characterization and thermal production technologies. The successful application of these technologies would result in expanding their implementation throughout the Wilmington Field and, through technology transfer, to other slope and basin clastic (SBC) reservoirs.

  19. INCREASING HEAVY OIL RESERVES IN THE WILMINGTON OIL FIELD THROUGH ADVANCED RESERVOIR CHARACTERIZATION AND THERMAL PRODUCTION TECHNOLOGIES

    SciTech Connect (OSTI)

    Scott Hara

    2001-06-27

    The objective of this project is to increase the recoverable heavy oil reserves within sections of the Wilmington Oil Field, near Long Beach, California through the testing and application of advanced reservoir characterization and thermal production technologies. The successful application of these technologies will result in expanding their implementation throughout the Wilmington Field and, through technology transfer, to other slope and basin clastic (SBC) reservoirs. The existing steamflood in the Tar zone of Fault Block II-A (Tar II-A) has been relatively inefficient because of several producibility problems which are common in SBC reservoirs: inadequate characterization of the heterogeneous turbidite sands, high permeability thief zones, low gravity oil and non-uniform distribution of the remaining oil. This has resulted in poor sweep efficiency, high steam-oil ratios, and early steam breakthrough. Operational problems related to steam breakthrough, high reservoir pressure, and unconsolidated sands have caused premature well and downhole equipment failures. In aggregate, these reservoir and operational constraints have resulted in increased operating costs and decreased recoverable reserves. A suite of advanced reservoir characterization and thermal production technologies are being applied during the project to improve oil recovery and reduce operating costs.

  20. INCREASING HEAVY OIL RESERVES IN THE WILMINGTON OIL FIELD THROUGH ADVANCED RESERVOIR CHARACTERIZATION AND THERMAL PRODUCTION TECHNOLOGIES

    SciTech Connect (OSTI)

    Unknown

    2001-08-08

    The objective of this project is to increase the recoverable heavy oil reserves within sections of the Wilmington Oil Field, near Long Beach, California, through the testing and application of advanced reservoir characterization and thermal production technologies. The hope is that successful application of these technologies will result in their implementation throughout the Wilmington Field and, through technology transfer, will be extended to increase the recoverable oil reserves in other slope and basin clastic (SBC) reservoirs. The existing steamflood in the Tar zone of Fault Block II-A (Tar II-A) has been relatively inefficient because of several producibility problems which are common in SBC reservoirs: inadequate characterization of the heterogeneous turbidite sands, high permeability thief zones, low gravity oil and non-uniform distribution of the remaining oil. This has resulted in poor sweep efficiency, high steam-oil ratios, and early steam breakthrough. Operational problems related to steam breakthrough, high reservoir pressure, and unconsolidated sands have caused premature well and downhole equipment failures. In aggregate, these reservoir and operational constraints have resulted in increased operating costs and decreased recoverable reserves. A suite of advanced reservoir characterization and thermal production technologies are being applied during the project to improve oil recovery and reduce operating costs, including: (1) Development of three-dimensional (3-D) deterministic and stochastic reservoir simulation models--thermal or otherwise--to aid in reservoir management of the steamflood and post-steamflood phases and subsequent development work. (2) Development of computerized 3-D visualizations of the geologic and reservoir simulation models to aid reservoir surveillance and operations. (3) Perform detailed studies of the geochemical interactions between the steam and the formation rock and fluids. (4) Testing and proposed application of a novel alkaline-steam well completion technique for the containment of the unconsolidated formation sands and control of fluid entry and injection profiles. (5) Installation of a 2100 ft, 14 inch insulated, steam line beneath a harbor channel to supply steam to an island location. (6) Testing and proposed application of thermal recovery technologies to increase oil production and reserves: (a) Performing pilot tests of cyclic steam injection and production on new horizontal wells. (b) Performing pilot tests of hot water-alternating-steam (WAS) drive in the existing steam drive area to improve thermal efficiency. (7) Perform a pilot steamflood with the four horizontal injectors and producers using a pseudo steam-assisted gravity-drainage (SAGD) process. (8) Advanced reservoir management, through computer-aided access to production and geologic data to integrate reservoir characterization, engineering, monitoring and evaluation.

  1. Increasing Heavy Oil Reserves in the Wilmington Oil Field through Advanced Reservoir Characterization and Thermal Production Technologies

    SciTech Connect (OSTI)

    City of Long Beach; David K.Davies and Associates; Tidelands Oil Production Company; University of Southern California

    1999-06-25

    The objective of this project is to increase the recoverable heavy oil reserves within sections of the Wilmington Oil Field, near Long Beach, California. This is realized through the testing and application of advanced reservoir characterization and thermal production technologies. It is hoped that the successful application of these technologies will result in their implementation throughout the Wilmington Field and through technology transfer, will be extended to increase the recoverable oil reserves in other slope and basin clastic (SBC) reservoirs. The existing steamflood in the Tar zone of Fault Block (FB) II-A has been relatively insufficient because of several producability problems which are common in SBC reservoir; inadequate characterization of the heterogeneous turbidite sands, high permeability thief zones, low gravity oil and non-uniform distribution of the remaining oil. This has resulted in poor sweep efficiency, high steam-oil ratios, and early breakthrough. Operational problems related to steam breakthrough, high reservoir pressure, and unconsolidated sands have caused premature well and downhole equipment failures. In aggregate, these reservoir and operational constraints have resulted in increased operating costs and decreased recoverable reserves.

  2. Fire flood method for recovering petroleum from oil reservoirs of low permeability and temperature

    DOE Patents [OSTI]

    1984-08-14

    The present invention is directed to a method of enhanced oil recovery by fire flooding petroleum reservoirs characterized by a temperature of less than the critical temperature of carbon dioxide, a pore pressure greater than the saturated vapor pressure of carbon dioxide at said temperature (87.7.degree. F. at 1070 psia), and a permeability in the range of about 20 to 100 millidarcies. The in situ combustion of petroleum in the reservoir is provided by injecting into the reservoir a combustion supporting medium consisting essentially of oxygen, ozone, or a combination thereof. The heat of combustion and the products of this combustion which consist essentially of gaseous carbon dioxide and water vapor sufficiently decrease the viscosity of oil adjacent to fire front to form an oil bank which moves through the reservoir towards a recovery well ahead of the fire front. The gaseous carbon dioxide and the water vapor are driven into the reservoir ahead of the fire front by pressure at the injection well. As the gaseous carbon dioxide cools to less than about 88.degree. F. it is converted to liquid which is dissolved in the oil bank for further increasing the mobility thereof. By using essentially pure oxygen, ozone, or a combination thereof as the combustion supporting medium in these reservoirs the permeability requirements of the reservoirs are significantly decreased since the liquid carbon dioxide requires substantially less voidage volume than that required for gaseous combustion products.

  3. Cost Effective Surfactant Formulations for Improved Oil Recovery in Carbonate Reservoirs

    SciTech Connect (OSTI)

    William A. Goddard; Yongchun Tang; Patrick Shuler; Mario Blanco; Yongfu Wu

    2007-09-30

    This report summarizes work during the 30 month time period of this project. This was planned originally for 3-years duration, but due to its financial limitations, DOE halted funding after 2 years. The California Institute of Technology continued working on this project for an additional 6 months based on a no-cost extension granted by DOE. The objective of this project is to improve the performance of aqueous phase formulations that are designed to increase oil recovery from fractured, oil-wet carbonate reservoir rock. This process works by increasing the rate and extent of aqueous phase imbibition into the matrix blocks in the reservoir and thereby displacing crude oil normally not recovered in a conventional waterflood operation. The project had three major components: (1) developing methods for the rapid screening of surfactant formulations towards identifying candidates suitable for more detailed evaluation, (2) more fundamental studies to relate the chemical structure of acid components of an oil and surfactants in aqueous solution as relates to their tendency to wet a carbonate surface by oil or water, and (3) a more applied study where aqueous solutions of different commercial surfactants are examined for their ability to recover a West Texas crude oil from a limestone core via an imbibition process. The first item, regarding rapid screening methods for suitable surfactants has been summarized as a Topical Report. One promising surfactant screening protocol is based on the ability of a surfactant solution to remove aged crude oil that coats a clear calcite crystal (Iceland Spar). Good surfactant candidate solutions remove the most oil the quickest from the surface of these chips, plus change the apparent contact angle of the remaining oil droplets on the surface that thereby indicate increased water-wetting. The other fast surfactant screening method is based on the flotation behavior of powdered calcite in water. In this test protocol, first the calcite power is pre-treated to make the surface oil-wet. The next step is to add the pre-treated powder to a test tube and add a candidate aqueous surfactant formulation; the greater the percentage of the calcite that now sinks to the bottom rather than floats, the more effective the surfactant is in changing the solids to become now preferentially water-wet. Results from the screening test generally are consistent with surfactant oil recovery performance reported in the literature. The second effort is a more fundamental study. It considers the effect of chemical structures of different naphthenic acids (NA) dissolved in decane as model oils that render calcite surfaces oil-wet to a different degree. NAs are common to crude oil and are at least partially responsible for the frequent observation that carbonate reservoirs are oil-wet. Because pure NA compounds are used, trends in wetting behavior can be related to NA molecular structure as measured by solid adsorption, contact angle and our novel, simple flotation test with calcite. Experiments with different surfactants and NA-treated calcite powder provide information about mechanisms responsible for sought after reversal to a water-wet state. Key findings include: (1) more hydrophobic NA's are more prone to induce oil-wetting, and (2) recovery of the model oil from limestone core was better with cationic surfactants, but one nonionic surfactant, Igepal CO-530, also had favorable results. This portion of the project included theoretical calculations to investigate key basic properties of several NAs such as their acidic strength and their relative water/oil solubility, and relate this to their chemical structure. The third category of this project focused on the recovery of a light crude oil from West Texas (McElroy Field) from a carbonate rock (limestone outcrop). For this effort, the first item was to establish a suite of surfactants that would be compatible with the McElroy Field brine. Those were examined further for their ability to recover oil by imbibition. Results demonstrate several types of promising candida

  4. Fundamentals of Reservoir Surface Energy as Related to Surface Properties, Wettability, Capillary Action, and Oil Recovery from Fractured Reservoirs by Spontaneous Imbibition

    SciTech Connect (OSTI)

    Norman Morrow; Herbert Fischer; Yu Li; Geoffrey Mason; Douglas Ruth; Siddhartha Seth; Zhengxin Tong; Evren Unsal; Siluni Wickramathilaka; Shaochang Wo; Peigui Yin

    2008-06-30

    The objective of this project is to increase oil recovery from fractured reservoirs through improved fundamental understanding of the process of spontaneous imbibition by which oil is displaced from the rock matrix into the fractures. Spontaneous imbibition is fundamentally dependent on the reservoir surface free energy but this has never been investigated for rocks. In this project, the surface free energy of rocks will be determined by using liquids that can be solidified within the rock pore space at selected saturations. Thin sections of the rock then provide a two-dimensional view of the rock minerals and the occupant phases. Saturations and oil/rock, water/rock, and oil/water surface areas will be determined by advanced petrographic analysis and the surface free energy which drives spontaneous imbibition will be determined as a function of increase in wetting phase saturation. The inherent loss in surface free energy resulting from capillary instabilities at the microscopic (pore level) scale will be distinguished from the decrease in surface free energy that drives spontaneous imbibition. A mathematical network/numerical model will be developed and tested against experimental results of recovery versus time over broad variation of key factors such as rock properties, fluid phase viscosities, sample size, shape and boundary conditions. Two fundamentally important, but not previously considered, parameters of spontaneous imbibition, the capillary pressure acting to oppose production of oil at the outflow face and the pressure in the non-wetting phase at the no-flow boundary versus time, will also be measured and modeled. Simulation and network models will also be tested against special case solutions provided by analytic models. In the second stage of the project, application of the fundamental concepts developed in the first stage of the project will be demonstrated. The fundamental ideas, measurements, and analytic/numerical modeling will be applied to mixed-wet rocks. Imbibition measurements will include novel sensitive pressure measurements designed to elucidate the basic mechanisms that determine induction time and drive the very slow rate of spontaneous imbibition commonly observed for mixed-wet rocks. In further demonstration of concepts, three approaches to improved oil recovery from fractured reservoirs will be tested; use of surfactants to promote imbibition in oil wet rocks by wettability alteration: manipulation of injection brine composition: reduction of the capillary back pressure which opposes production of oil at the fracture face.

  5. IMPROVED OIL RECOVERY IN MISSISSIPPIAN CARBONATE RESERVOIRS OF KANSAS - NEAR TERM - CLASS 2

    SciTech Connect (OSTI)

    Timothy R. Carr; Don W. Green; G. Paul Willhite

    2000-04-30

    This annual report describes progress during the final year of the project entitled ''Improved Oil Recovery in Mississippian Carbonate Reservoirs in Kansas''. This project funded under the Department of Energy's Class 2 program targets improving the reservoir performance of mature oil fields located in shallow shelf carbonate reservoirs. The focus of the project was development and demonstration of cost-effective reservoir description and management technologies to extend the economic life of mature reservoirs in Kansas and the mid-continent. As part of the project, tools and techniques for reservoir description and management were developed, modified and demonstrated, including PfEFFER spreadsheet log analysis software. The world-wide-web was used to provide rapid and flexible dissemination of the project results through the Internet. A summary of demonstration phase at the Schaben and Ness City North sites demonstrates the effectiveness of the proposed reservoir management strategies and technologies. At the Schaben Field, a total of 22 additional locations were evaluated based on the reservoir characterization and simulation studies and resulted in a significant incremental production increase. At Ness City North Field, a horizontal infill well (Mull Ummel No.4H) was planned and drilled based on the results of reservoir characterization and simulation studies to optimize the location and length. The well produced excellent and predicted oil rates for the first two months. Unexpected presence of vertical shale intervals in the lateral resulted in loss of the hole. While the horizontal well was not economically successful, the technology was demonstrated to have potential to recover significant additional reserves in Kansas and the Midcontinent. Several low-cost approaches were developed to evaluate candidate reservoirs for potential horizontal well applications at the field scale, lease level, and well level, and enable the small independent producer to identify efficiently candidate reservoirs and also to predict the performance of horizontal well applications.

  6. INCREASING HEAVY OIL RESERVES IN THE WILMINGTON OIL FIELD THROUGH ADVANCED RESERVOIR CHARACTERIZATION AND THERMAL PRODUCTION TECHNOLOGIES

    SciTech Connect (OSTI)

    Scott Hara

    2003-09-04

    The overall objective of this project is to increase heavy oil reserves in slope and basin clastic (SBC) reservoirs through the application of advanced reservoir characterization and thermal production technologies. The project involves improving thermal recovery techniques in the Tar Zone of Fault Blocks II-A and V (Tar II-A and Tar V) of the Wilmington Field in Los Angeles County, near Long Beach, California. A primary objective is to transfer technology which can be applied in other heavy oil formations of the Wilmington Field and other SBC reservoirs, including those under waterflood. The thermal recovery operations in the Tar II-A and Tar V have been relatively inefficient because of several producibility problems which are common in SBC reservoirs. Inadequate characterization of the heterogeneous turbidite sands, high permeability thief zones, low gravity oil, and nonuniform distribution of remaining oil have all contributed to poor sweep efficiency, high steam-oil ratios, and early steam breakthrough. Operational problems related to steam breakthrough, high reservoir pressure, and unconsolidated formation sands have caused premature well and downhole equipment failures. In aggregate, these reservoir and operational constraints have resulted in increased operating costs and decreased recoverable reserves. The advanced technologies to be applied include: (1) Develop three-dimensional (3-D) deterministic and stochastic geologic models. (2) Develop 3-D deterministic and stochastic thermal reservoir simulation models to aid in reservoir management and subsequent development work. (3) Develop computerized 3-D visualizations of the geologic and reservoir simulation models to aid in analysis. (4) Perform detailed study on the geochemical interactions between the steam and the formation rock and fluids. (5) Pilot steam injection and production via four new horizontal wells (2 producers and 2 injectors). (6) Hot water alternating steam (WAS) drive pilot in the existing steam drive area to improve thermal efficiency. (7) Installing an 2400 foot insulated, subsurface harbor channel crossing to supply steam to an island location. (8) Test a novel alkaline steam completion technique to control well sanding problems and fluid entry profiles. (9) Advanced reservoir management through computer-aided access to production and geologic data to integrate reservoir characterization, engineering, monitoring, and evaluation.

  7. INCREASING HEAVY OIL RESERVES IN THE WILMINGTON OIL FIELD THROUGH ADVANCED RESERVOIR CHARACTERIZATION AND THERMAL PRODUCTION TECHNOLOGIES

    SciTech Connect (OSTI)

    Scott Hara

    2003-06-04

    The overall objective of this project is to increase heavy oil reserves in slope and basin clastic (SBC) reservoirs through the application of advanced reservoir characterization and thermal production technologies. The project involves improving thermal recovery techniques in the Tar Zone of Fault Blocks II-A and V (Tar II-A and Tar V) of the Wilmington Field in Los Angeles County, near Long Beach, California. A primary objective is to transfer technology which can be applied in other heavy oil formations of the Wilmington Field and other SBC reservoirs, including those under waterflood. The thermal recovery operations in the Tar II-A and Tar V have been relatively inefficient because of several producibility problems which are common in SBC reservoirs. Inadequate characterization of the heterogeneous turbidite sands, high permeability thief zones, low gravity oil, and nonuniform distribution of remaining oil have all contributed to poor sweep efficiency, high steam-oil ratios, and early steam breakthrough. Operational problems related to steam breakthrough, high reservoir pressure, and unconsolidated formation sands have caused premature well and downhole equipment failures. In aggregate, these reservoir and operational constraints have resulted in increased operating costs and decreased recoverable reserves. The advanced technologies to be applied include: (1) Develop three-dimensional (3-D) deterministic and stochastic geologic models. (2) Develop 3-D deterministic and stochastic thermal reservoir simulation models to aid in reservoir management and subsequent development work. (3) Develop computerized 3-D visualizations of the geologic and reservoir simulation models to aid in analysis. (4) Perform detailed study on the geochemical interactions between the steam and the formation rock and fluids. (5) Pilot steam injection and production via four new horizontal wells (2 producers and 2 injectors). (6) Hot water alternating steam (WAS) drive pilot in the existing steam drive area to improve thermal efficiency. (7) Installing an 2400 foot insulated, subsurface harbor channel crossing to supply steam to an island location. (8) Test a novel alkaline steam completion technique to control well sanding problems and fluid entry profiles. (9) Advanced reservoir management through computer-aided access to production and geologic data to integrate reservoir characterization, engineering, monitoring, and evaluation.

  8. INCREASING HEAVY OIL RESERVES IN THE WILMINGTON OIL FIELD THROUGH ADVANCED RESERVOIR CHARACTERIZATION AND THERMAL PRODUCTION TECHNOLOGIES

    SciTech Connect (OSTI)

    Scott Hara

    2004-03-05

    The overall objective of this project is to increase heavy oil reserves in slope and basin clastic (SBC) reservoirs through the application of advanced reservoir characterization and thermal production technologies. The project involves improving thermal recovery techniques in the Tar Zone of Fault Blocks II-A and V (Tar II-A and Tar V) of the Wilmington Field in Los Angeles County, near Long Beach, California. A primary objective is to transfer technology which can be applied in other heavy oil formations of the Wilmington Field and other SBC reservoirs, including those under waterflood. The thermal recovery operations in the Tar II-A and Tar V have been relatively inefficient because of several producibility problems which are common in SBC reservoirs. Inadequate characterization of the heterogeneous turbidite sands, high permeability thief zones, low gravity oil, and nonuniform distribution of remaining oil have all contributed to poor sweep efficiency, high steam-oil ratios, and early steam breakthrough. Operational problems related to steam breakthrough, high reservoir pressure, and unconsolidated formation sands have caused premature well and downhole equipment failures. In aggregate, these reservoir and operational constraints have resulted in increased operating costs and decreased recoverable reserves. The advanced technologies to be applied include: (1) Develop three-dimensional (3-D) deterministic and stochastic geologic models. (2) Develop 3-D deterministic and stochastic thermal reservoir simulation models to aid in reservoir management and subsequent development work. (3) Develop computerized 3-D visualizations of the geologic and reservoir simulation models to aid in analysis. (4) Perform detailed study on the geochemical interactions between the steam and the formation rock and fluids. (5) Pilot steam injection and production via four new horizontal wells (2 producers and 2 injectors). (6) Hot water alternating steam (WAS) drive pilot in the existing steam drive area to improve thermal efficiency. (7) Installing an 2400 foot insulated, subsurface harbor channel crossing to supply steam to an island location. (8) Test a novel alkaline steam completion technique to control well sanding problems and fluid entry profiles. (9) Advanced reservoir management through computer-aided access to production and geologic data to integrate reservoir characterization, engineering, monitoring, and evaluation.

  9. Evaluation of Reservoir Wettability and its Effect on Oil Recovery

    SciTech Connect (OSTI)

    Buckley, Jill S.

    2002-01-29

    The objectives of this five-year project were: (1) to achieve improved understanding of the surface and interfacial properties of crude oils and their interactions with mineral surfaces, (2) to apply the results of surface studies to improve predictions of oil production from laboratory measurements, and (3) to use the results of this research to recommend ways to improve oil recovery by waterflooding.

  10. Post Waterflood CO2 Miscible Flood in Light Oil, Fluvial-Dominated Deltaic Reservoir, Class I

    SciTech Connect (OSTI)

    Bou-Mikael, Sami

    2002-02-05

    This report demonstrates the effectiveness of the CO2 miscible process in Fluvial Dominated Deltaic reservoirs. It also evaluated the use of horizontal CO2 injection wells to improve the overall sweep efficiency. A database of FDD reservoirs for the gulf coast region was developed by LSU, using a screening model developed by Texaco Research Center in Houston. The results of the information gained in this project is disseminated throughout the oil industry via a series of SPE papers and industry open forums.

  11. Evaluation of Reservoir Wettability and its Effect on Oil Recovery

    SciTech Connect (OSTI)

    Buckley, Jill S.

    1999-07-01

    The objective of this five-year project are: (1) to achieve improved understanding of the surface and interfacial properties of crude oils and their interactions with mineral surfaces, (2) to apply the results of surface studies to improve predictions of oil production from laboratory measurements, and (3) to use the results of this research to recommend ways to improve oil recovery by waterflooding. During the second year of this project we have tested the generality of the proposed mechanisms by which crude oil components can alter wetting. Using these mechanisms, we have begun a program of characterizing crude oils with respect to their wettability altering potential. Wettability assessment has been improved by replacing glass with mica as a standard surface material and crude oils have been used to alter wetting in simple square glass capillary tubes in which the subsequent imbibition of water can be followed visually.

  12. Virginia Crude Oil Reserves in Nonproducing Reservoirs (Million...

    Annual Energy Outlook [U.S. Energy Information Administration (EIA)]

    of individual company data. Release Date: 11192015 Next Release Date: 12312016 Referring Pages: Proved Nonproducing Reserves of Crude Oil Virginia Proved Nonproducing Reserves...

  13. U.S. Crude Oil + Lease Condensate New Reservoir Discoveries in Old Fields

    U.S. Energy Information Administration (EIA) Indexed Site

    (Million Barrels) New Reservoir Discoveries in Old Fields (Million Barrels) U.S. Crude Oil + Lease Condensate New Reservoir Discoveries in Old Fields (Million Barrels) Decade Year-0 Year-1 Year-2 Year-3 Year-4 Year-5 Year-6 Year-7 Year-8 Year-9 2000's 95 2010's 169 88 129 343 219 - = No Data Reported; -- = Not Applicable; NA = Not Available; W = Withheld to avoid disclosure of individual company data. Release Date: 11/19/2015 Next Release Date: 12/31/2016 Referring Pages: Crude Oil plus

  14. New Mexico--East Crude Oil Reserves in Nonproducing Reservoirs (Million

    U.S. Energy Information Administration (EIA) Indexed Site

    Barrels) Crude Oil Reserves in Nonproducing Reservoirs (Million Barrels) New Mexico--East Crude Oil Reserves in Nonproducing Reservoirs (Million Barrels) Decade Year-0 Year-1 Year-2 Year-3 Year-4 Year-5 Year-6 Year-7 Year-8 Year-9 1990's NA NA 97 156 2000's 91 161 146 133 142 171 159 147 136 149 2010's 180 185 232 304 460 - = No Data Reported; -- = Not Applicable; NA = Not Available; W = Withheld to avoid disclosure of individual company data. Release Date: 11/19/2015 Next Release Date:

  15. New Mexico--West Crude Oil Reserves in Nonproducing Reservoirs (Million

    U.S. Energy Information Administration (EIA) Indexed Site

    Barrels) Crude Oil Reserves in Nonproducing Reservoirs (Million Barrels) New Mexico--West Crude Oil Reserves in Nonproducing Reservoirs (Million Barrels) Decade Year-0 Year-1 Year-2 Year-3 Year-4 Year-5 Year-6 Year-7 Year-8 Year-9 1990's NA NA 0 0 2000's 0 0 0 0 0 0 0 0 0 0 2010's 0 0 0 10 29 - = No Data Reported; -- = Not Applicable; NA = Not Available; W = Withheld to avoid disclosure of individual company data. Release Date: 11/19/2015 Next Release Date: 12/31/2016 Referring Pages: Proved

  16. Calif--Coastal Region Onshore Crude Oil Reserves in Nonproducing Reservoirs

    U.S. Energy Information Administration (EIA) Indexed Site

    (Million Barrels) Crude Oil Reserves in Nonproducing Reservoirs (Million Barrels) Calif--Coastal Region Onshore Crude Oil Reserves in Nonproducing Reservoirs (Million Barrels) Decade Year-0 Year-1 Year-2 Year-3 Year-4 Year-5 Year-6 Year-7 Year-8 Year-9 1990's NA NA 137 134 2000's 130 148 61 61 16 70 85 42 26 51 2010's 199 248 293 280 281 - = No Data Reported; -- = Not Applicable; NA = Not Available; W = Withheld to avoid disclosure of individual company data. Release Date: 11/19/2015 Next

  17. ,"New Mexico--East Crude Oil Reserves in Nonproducing Reservoirs (Million Barrels)"

    U.S. Energy Information Administration (EIA) Indexed Site

    Crude Oil Reserves in Nonproducing Reservoirs (Million Barrels)" ,"Click worksheet name or tab at bottom for data" ,"Worksheet Name","Description","# Of Series","Frequency","Latest Data for" ,"Data 1","New Mexico--East Crude Oil Reserves in Nonproducing Reservoirs (Million Barrels)",1,"Annual",2014 ,"Release Date:","11/19/2015" ,"Next Release Date:","12/31/2016"

  18. ,"New Mexico--West Crude Oil Reserves in Nonproducing Reservoirs (Million Barrels)"

    U.S. Energy Information Administration (EIA) Indexed Site

    Crude Oil Reserves in Nonproducing Reservoirs (Million Barrels)" ,"Click worksheet name or tab at bottom for data" ,"Worksheet Name","Description","# Of Series","Frequency","Latest Data for" ,"Data 1","New Mexico--West Crude Oil Reserves in Nonproducing Reservoirs (Million Barrels)",1,"Annual",2014 ,"Release Date:","11/19/2015" ,"Next Release Date:","12/31/2016"

  19. ,"Texas--State Offshore Crude Oil Reserves in Nonproducing Reservoirs (Million Barrels)"

    U.S. Energy Information Administration (EIA) Indexed Site

    Crude Oil Reserves in Nonproducing Reservoirs (Million Barrels)" ,"Click worksheet name or tab at bottom for data" ,"Worksheet Name","Description","# Of Series","Frequency","Latest Data for" ,"Data 1","Texas--State Offshore Crude Oil Reserves in Nonproducing Reservoirs (Million Barrels)",1,"Annual",2014 ,"Release Date:","11/19/2015" ,"Next Release

  20. ,"Calif--Coastal Region Onshore Crude Oil Reserves in Nonproducing Reservoirs (Million Barrels)"

    U.S. Energy Information Administration (EIA) Indexed Site

    Crude Oil Reserves in Nonproducing Reservoirs (Million Barrels)" ,"Click worksheet name or tab at bottom for data" ,"Worksheet Name","Description","# Of Series","Frequency","Latest Data for" ,"Data 1","Calif--Coastal Region Onshore Crude Oil Reserves in Nonproducing Reservoirs (Million Barrels)",1,"Annual",2014 ,"Release Date:","11/19/2015" ,"Next Release

  1. ,"California--State Offshore Crude Oil Reserves in Nonproducing Reservoirs (Million Barrels)"

    U.S. Energy Information Administration (EIA) Indexed Site

    Crude Oil Reserves in Nonproducing Reservoirs (Million Barrels)" ,"Click worksheet name or tab at bottom for data" ,"Worksheet Name","Description","# Of Series","Frequency","Latest Data for" ,"Data 1","California--State Offshore Crude Oil Reserves in Nonproducing Reservoirs (Million Barrels)",1,"Annual",2014 ,"Release Date:","11/19/2015" ,"Next Release

  2. ,"Federal Offshore--California Crude Oil Reserves in Nonproducing Reservoirs (Million Barrels)"

    U.S. Energy Information Administration (EIA) Indexed Site

    Crude Oil Reserves in Nonproducing Reservoirs (Million Barrels)" ,"Click worksheet name or tab at bottom for data" ,"Worksheet Name","Description","# Of Series","Frequency","Latest Data for" ,"Data 1","Federal Offshore--California Crude Oil Reserves in Nonproducing Reservoirs (Million Barrels)",1,"Annual",2014 ,"Release Date:","11/19/2015" ,"Next Release

  3. ,"Louisiana--South Onshore Crude Oil Reserves in Nonproducing Reservoirs (Million Barrels)"

    U.S. Energy Information Administration (EIA) Indexed Site

    Crude Oil Reserves in Nonproducing Reservoirs (Million Barrels)" ,"Click worksheet name or tab at bottom for data" ,"Worksheet Name","Description","# Of Series","Frequency","Latest Data for" ,"Data 1","Louisiana--South Onshore Crude Oil Reserves in Nonproducing Reservoirs (Million Barrels)",1,"Annual",2014 ,"Release Date:","11/19/2015" ,"Next Release

  4. ,"Louisiana--State Offshore Crude Oil Reserves in Nonproducing Reservoirs (Million Barrels)"

    U.S. Energy Information Administration (EIA) Indexed Site

    Crude Oil Reserves in Nonproducing Reservoirs (Million Barrels)" ,"Click worksheet name or tab at bottom for data" ,"Worksheet Name","Description","# Of Series","Frequency","Latest Data for" ,"Data 1","Louisiana--State Offshore Crude Oil Reserves in Nonproducing Reservoirs (Million Barrels)",1,"Annual",2014 ,"Release Date:","11/19/2015" ,"Next Release

  5. Establishment of an oil and gas database for increased recovery and characterization of oil and gas carbonate reservoir heterogeneity. Appendix 1, Volume 1

    SciTech Connect (OSTI)

    Kopaska-Merkel, D.C.; Moore, H.E. Jr.; Mann, S.D.; Hall, D.R.

    1992-06-01

    This volume contains maps, well logging correlated to porosity and permeability, structural cross section, graph of production history, porosity vs. natural log permeability plot, detailed core log, paragenetic sequence and reservoir characterization sheet of the following fields in southwest Alabama: Appleton oil field; Barnett oil field; Barrytown oil field; Big Escambia Creek gas and condensate field; Blacksher oil field; Broken Leg Creed oil field; Bucatunna Creed oil field; Chappell Hill oil field; Chatom gas and condensate field; Choctaw Ridge oil field; Chunchula gas and condensate field; Cold Creek oil field; Copeland gas and condensate field; Crosbys Creed gas and condensate field; and East Barnett oil field. (AT)

  6. Establishment of an oil and gas database for increased recovery and characterization of oil and gas carbonate reservoir heterogeneity. [Jurassic Smackover Formation

    SciTech Connect (OSTI)

    Kopaska-Merkel, D.C.; Moore, H.E. Jr.; Mann, S.D.; Hall, D.R.

    1992-06-01

    This volume contains maps, well logging correlated to porosity and permeability, structural cross section, graph of production history, porosity vs. natural log permeability plot, detailed core log, paragenetic sequence and reservoir characterization sheet of the following fields in southwest Alabama: Appleton oil field; Barnett oil field; Barrytown oil field; Big Escambia Creek gas and condensate field; Blacksher oil field; Broken Leg Creed oil field; Bucatunna Creed oil field; Chappell Hill oil field; Chatom gas and condensate field; Choctaw Ridge oil field; Chunchula gas and condensate field; Cold Creek oil field; Copeland gas and condensate field; Crosbys Creed gas and condensate field; and East Barnett oil field. (AT)

  7. Development Practices for Optimized MEOR in Shallow Heavy Oil Reservoirs

    SciTech Connect (OSTI)

    Shari Dunn-Norman

    2006-09-30

    The goal of this project is to demonstrate an economically viable and sustainable method of producing shallow heavy oil reserves in southwest Missouri and southeast Kansas using a combination of microbial enhanced oil recovery (MEOR) and hydraulic fracturing of vertical wells.

  8. INCREASING HEAVY OIL RESERVES IN THE WILMINGTON OIL FIELD THROUGH ADVANCED RESERVOIR CHARACTERIZATION AND THERMAL PRODUCTION TECHNOLOGIES

    SciTech Connect (OSTI)

    Scott Hara

    2001-05-07

    The project involves using advanced reservoir characterization and thermal production technologies to improve thermal recovery techniques and lower operating and capital costs in a slope and basin clastic (SBC) reservoir in the Wilmington field, Los Angeles Co., CA. Through September 2000, project work has been completed on the following activities: data preparation; basic reservoir engineering; developing a deterministic three dimensional (3-D) geologic model, a 3-D deterministic reservoir simulation model and a rock-log model; well drilling and completions; and surface facilities on the Fault Block II-A Tar Zone (Tar II-A). Work is continuing on improving core analysis techniques, final reservoir tracer work, operational work and research studies to prevent thermal-related formation compaction in the Tar II-A steamflood area, and operational work on the Tar V steamflood pilot and Tar II-A post steamflood projects. Work was discontinued on the stochastic geologic model and developing a 3-D stochastic thermal reservoir simulation model of the Tar II-A Zone so the project team could use the 3-D deterministic reservoir simulation model to provide alternatives for the Tar II-A post steamflood operations and shale compaction studies. The project team spent the fourth quarter 2000 performing well work and reservoir surveillance on the Tar II-A post-steamflood project and the Tar V horizontal well steamflood pilot. Expanding thermal recovery operations to other sections of the Wilmington Oil Field, including the Tar V horizontal well pilot steamflood project, is a critical part of the City of Long Beach and Tidelands Oil Production Company's development strategy for the field. The current steamflood operations in the Tar V pilot are economical, but recent performance is below projections because of wellbore mechanical limitations that are being evaluated.

  9. Improving CO2 Efficiency for Recovering Oil in Heterogeneous Reservoirs

    SciTech Connect (OSTI)

    Grigg, Reid B.; Svec, Robert K.

    2003-03-10

    The work strived to improve industry understanding of CO2 flooding mechanisms with the ultimate goal of economically recovering more of the U.S. oil reserves. The principle interests are in the related fields of mobility control and injectivity.

  10. A combination of streamtube and geostatical simulation methodologies for the study of large oil reservoirs

    SciTech Connect (OSTI)

    Chakravarty, A.; Emanuel, A.S.; Bernath, J.A.

    1997-08-01

    The application of streamtube models for reservoir simulation has an extensive history in the oil industry. Although these models are strictly applicable only to fields under voidage balance, they have proved to be useful in a large number of fields provided that there is no solution gas evolution and production. These models combine the benefit of very fast computational time with the practical ability to model a large reservoir over the course of its history. These models do not, however, directly incorporate the detailed geological information that recent experience has taught is important. This paper presents a technique for mapping the saturation information contained in a history matched streamtube model onto a detailed geostatistically derived finite difference grid. With this technique, the saturation information in a streamtube model, data that is actually statistical in nature, can be identified with actual physical locations in a field and a picture of the remaining oil saturation can be determined. Alternatively, the streamtube model can be used to simulate the early development history of a field and the saturation data then used to initialize detailed late time finite difference models. The proposed method is presented through an example application to the Ninian reservoir. This reservoir, located in the North Sea (UK), is a heterogeneous sandstone characterized by a line drive waterflood, with about 160 wells, and a 16 year history. The reservoir was satisfactorily history matched and mapped for remaining oil saturation. A comparison to 3-D seismic survey and recently drilled wells have provided preliminary verification.

  11. POST WATERFLOOD CO2 MISCIBLE FLOOD IN LIGHT OIL FLUVIAL DOMINATED DELTAIC RESERVOIR

    SciTech Connect (OSTI)

    Tim Tipton

    2004-04-06

    Texaco Exploration and Production Inc. (TEPI) and the US Department of Energy (DOE) entered into a cost sharing cooperative agreement to conduct an Enhanced Oil Recovery demonstration project at Port Neches. The field is located in Orange County near Beaumont, Texas, and shown in Appendix A. The project would demonstrate the effectiveness of the CO{sub 2} miscible process in Fluvial Dominated Deltaic reservoirs. It would also evaluate the use of horizontal CO{sub 2} injection wells to improve the overall sweep efficiency and determine the recovery efficiency of CO{sub 2} floods in waterflooded and partial waterdrive reservoirs. Texaco's objective on this project was (1) to utilize all available technologies, and to develop new ones, and (2) to design a CO{sub 2} flood process which is cost effective and can be applied to many other reservoirs throughout the US. A database of potential reservoirs for the gulf coast region was developed by LSU, using a screening model developed by Texaco Research Center in Houston. A PC-based CO{sub 2} screening model was developed and the aforementioned database generated to show the utility of this technology throughout the US. Finally, the results and the information gained from this project was disseminated throughout the oil industry via a series of SPE papers and industry open forums. Reservoir characterization efforts for the Marginulina sand shown in Appendix C, were accomplished utilizing conventional and advanced technologies including 3-D seismic. Sidewall and conventional cores were cut and analyzed, lab tests were conducted on reservoir fluids and reservoir voidage was monitored as shown in Appendices B through M. Texaco has utilized the above data to develop a Stratamodel to best describe and characterize the reservoir and to use it as input for the compositional simulator. The compositional model was revised several times to integrate the new data from the 3-D seismic and field performance under CO{sub 2} injection, to ultimately develop an accurate economic model. The Port Neches CO{sub 2} Project concentrated upon the tertiary oil recoveries, to be obtained from two sections of the reservoir, which were at different stages of depletion. The large waterflooded fault block had an average remaining oil saturation of 31% while the small partial waterdrive fault block had an oil saturation of 43%.

  12. Improved Oil Recovery in Fluvial Dominated Deltaic Reservoirs of Kansas - Near-Term

    SciTech Connect (OSTI)

    Green, D.W.; McCune, D.; Michnick, M.; Reynolds, R.; Walton, A.; Watney, L.; Willhite G.P.

    1999-10-29

    The objective of this project is to address waterflood problems of the type found in Morrow sandstone reservoirs in southwestern Kansas and in Cherokee Group reservoirs in southeastern Kansas. Two demonstration sites operated by different independent oil operators are involved in this project. The Stewart Field is located in Finney County, Kansas and is operated by PetroSantander, Inc. Te Nelson Lease is located in Allen County, Kansas, in the N.E. Savonburg Field and is operated by James E. Russell Petroleum, Inc. General topics to be addressed are (1) reservoir management and performance evaluation, (2) waterflood optimization, and (3) the demonstration of recovery processes involving off-the-shelf technologies which can be used to enhance waterflood recovery, increase reserves, and reduce the abandonment rate of these reservoir types. In the Stewart Project, the reservoir management portion of the project conducted during Budget Period 1 involved performance evaluation. This included (1) reservoir characterization and the development of a reservoir database, (2) volumetric analysis to evaluate production performance, (3) reservoir modeling, (4) laboratory work, (5) identification of operational problems, (6) identification of unrecovered mobile oil and estimation of recovery factors, and (7) identification of the most efficient and economical recovery process. To accomplish these objectives the initial budget period was subdivided into three major tasks. The tasks were (1) geological and engineering analysis, (2) laboratory testing, and (3) unitization. Due to the presence of different operators within the field, it was necessary to unitize the field in order to demonstrate a field-wide improved recovery process. This work was completed and the project moved into Budget Period 2.

  13. Improved Oil Recovery in Fluvial Dominated Deltaic Reservoirs of Kansas - Near-Term

    SciTech Connect (OSTI)

    Green, Don W.; McCune, A.D.; Michnick, M.; Reynolds, R.; Walton, A.; Watney, L.; Willhite, G. Paul

    1999-11-03

    The objective of this project is to address waterflood problems of the type found in Morrow sandstone reservoirs in southwestern Kansas and in Cherokee Group reservoirs in southeastern Kansas. Two demonstration sites operated by different independent oil operators are involved in this project. The Stewart Field is located in Finney County, Kansas and is operated by PetroSantander, Inc. Te Nelson Lease is located in Allen County, Kansas, in the N.E. Savonburg Field and is operated by James E. Russell Petroleum, Inc. General topics to be addressed are (1) reservoir management and performance evaluation, (2) waterflood optimization, and (3) the demonstration of recovery processes involving off-the-shelf technologies which can be used to enhance waterflood recovery, increase reserves, and reduce the abandonment rate of these reservoir types. In the Stewart Project, the reservoir management portion of the project conducted during Budget Period 1 involved performance evaluation. This included (1) reservoir characterization and the development of a reservoir database, (2) volumetric analysis to evaluate production performance, (3) reservoir modeling, (4) laboratory work, (5) identification of operational problems, (6) identification of unrecovered mobile oil and estimation of recovery factors, and (7) Identification of the most efficient and economical recovery process. To accomplish these objectives the initial budget period was subdivided into three major tasks. The tasks were (1) geological and engineering analysis, (2) laboratory testing, and (3) unitization. Due to the presence of different operators within the field, it was necessary to unitize the field in order to demonstrate a field-wide improved recovery process. This work was completed and the project moved into Budget Period 2.

  14. INCREASING HEAVY OIL RESERVES IN THE WILMINGTON OIL FIELD THROUGH ADVANCED RESERVOIR CHARACTERIZATION AND THERMAL PRODUCTION TECHNOLOGIES

    SciTech Connect (OSTI)

    Scott Hara

    2002-11-08

    The project involves using advanced reservoir characterization and thermal production technologies to improve thermal recovery techniques and lower operating and capital costs in a slope and basin clastic (SBC) reservoir in the Wilmington field, Los Angeles Co., CA. Through June 2002, project work has been completed on the following activities: data preparation; basic reservoir engineering; developing a deterministic three dimensional (3-D) geologic model, a 3-D deterministic reservoir simulation model and a rock-log model; well drilling and completions; and surface facilities on the Fault Block II-A Tar Zone (Tar II-A). Work is continuing on research to understand the geochemistry and process regarding the sand consolidation well completion technique, final reservoir tracer work, operational work and research studies to prevent thermal-related formation compaction in the Tar II-A steamflood area, and operational work on the Tar V post-steamflood pilot and Tar II-A post-steamflood projects. During the Third Quarter 2002, the project team essentially completed implementing the accelerated oil recovery and reservoir cooling plan for the Tar II-A post-steamflood project developed in March 2002 and is proceeding with additional related work. The project team has completed developing laboratory research procedures to analyze the sand consolidation well completion technique and will initiate work in the fourth quarter. The Tar V pilot steamflood project terminated hot water injection and converted to post-steamflood cold water injection on April 19, 2002. Proposals have been approved to repair two sand consolidated horizontal wells that sanded up, Tar II-A well UP-955 and Tar V well J-205, with gravel-packed inner liner jobs to be performed next quarter. Other well work to be performed next quarter is to convert well L-337 to a Tar V water injector and to recomplete vertical well A-194 as a Tar V interior steamflood pattern producer. Plans have been approved to drill and complete well A-605 in Tar V in the first quarter 2003. Plans have been approved to update the Tar II-A 3-D deterministic reservoir simulation model and run sensitivity cases to evaluate the accelerated oil recovery and reservoir cooling plan. The Tar II-A post-steamflood operation started in February 1999 and steam chest fillup occurred in September-October 1999. The targeted reservoir pressures in the ''T'' and ''D'' sands are maintained at 90 {+-} 5% hydrostatic levels by controlling water injection and gross fluid production and through the bimonthly pressure monitoring program enacted at the start of the post-steamflood phase. Well work related to the Tar II-A accelerated oil recovery and reservoir cooling plan began in March 2002 with oil production increasing from 1009 BOPD in the first quarter to 1145 BOPD in the third quarter. Reservoir pressures have been increased during the quarter from 88% to 91% hydrostatic levels in the ''T'' sands and from 91% to 94% hydrostatic levels in the ''D'' sands. Well work during the quarter is described in the Reservoir Management section. The post-steamflood production performance in the Tar V pilot project has been below projections because of wellbore mechanical limitations and the loss of a horizontal producer a second time to sand inflow that are being addressed in the fourth quarter. As the fluid production temperatures exceeded 350 F, our self-imposed temperature limit, the pilot steamflood was converted to a hot waterflood project in June 2001 and converted to cold water injection on April 19, 2002.

  15. Improved Oil Recovery in Fluvial Dominated Deltaic Reservoirs of Kansas - Near-Term

    SciTech Connect (OSTI)

    A. Walton; Don W. Green; G. Paul Whillhite; L. Schoeling; L. Watney; M. Michnick; R. Reynolds

    1997-07-15

    The objective of this project is to address waterflood problems of the type found in Morrow sandstone reservoirs in southwestern Kansas and in Cherokee Group reservoirs in southeastern Kansas. Two demonstration sites operated by different independent oil operators are involved in this project. The Stewart Field is located in Finney County, Kansas and is operated by North American Resources Company. The Nelson Lease is located in Allen County, Kansas, in the N.E. Savonburg Field and is operated by James E. Russell Petroleum, Inc. General topics to be addressed are 1) reservoir management and performance evaluation, 2) waterflood optimization, and 3) the demonstration of recovery processes involving off-the-shelf technologies which can be used to enhance waterflood recovery, increase reserves, and reduce the abandonment rate of these reservoir types. In the Stewart Project, the reservoir management portion of the project conducted during Budget Period 1 involved performance evaluation. This included 1) reservoir characterization and the development of a reservoir database, 2) volumetric analysis to evaluate production performance, 3) reservoir modeling, 4) laboratory work, 5) identification of operational problems, 6) identification of unrecovered mobile oil and estimation of recovery factors, and 7) identification of the most efficient and economical recovery process. To accomplish these objectives the initial budget period was subdivided into three major tasks. The tasks were 1) geological and engineering analysis, 2) laboratory testing, and 3) unitization. Due to the presence of different operators within the field, it was necessary to unitize the field in order to demonstrate a field-wide improved recovery process. This work was completed and the project moved into Budget Period 2. Budget Period 2 objectives consisted of the design, construction, and operation of a field-wide waterflood utilizing state-of-the-art, off-the-shelf technologies in an attempt to optimize secondary oil recovery. To accomplish these objectives the second budget period was subdivided into five major tasks. The tasks were 1) design and construction of a waterflood plant, 2) design and construction of a water injection system, 3) design and construction of tank battery consolidation and gathering system, 4) initiation of waterflood operations and reservoir management, and 5) technology transfer. Tasks 1-3 have been completed and water injection began in October 1995. In the Savonburg Project, the reservoir management portion involves performance evaluation. This work included 1) reservoir characterization and the development of a reservoir database, 2) identification of operational problems, 3) identification of near wellbore problems such as plugging caused from poor water quality, 4) identification of unrecovered mobile oil and estimation of recovery factors, and 5) preliminary identification of the most efficient and economical recovery process i.e., polymer augmented waterflooding or infill drilling (vertical or horizontal wells). To accomplish this work the initial budget period was subdivided into four major tasks. The tasks included 1) geological and engineering analysis, 2) waterplant optimization, 3) wellbore cleanup and pattern changes, and 4) field operations. This work was completed and the project has moved into Budget Period 2. The Budget Period 2 objectives consisted of continual optimization of this mature waterflood in an attempt to optimize secondary and tertiary oil recovery. To accomplish these objectives the second budget period is subdivided into six major tasks. The tasks were 1) waterplant development, 2) profile modification treatments, 3) pattern changes, new wells and wellbore cleanups, 4) reservoir development (polymer flooding), 5) field operations, and 6) technology transfer.

  16. Improved Oil Recovery in Fluvial Dominated Deltaic Reservoirs of Kansas Near Term

    SciTech Connect (OSTI)

    Green, D.W.; Willhlte, C.P.; Walton, A.; Schoeling, L.; Reynolds, R.; Michnick, M.; Watney, L.

    1997-04-15

    The objective of this project is to address waterflood problems of the type found in Morrow sandstone reservoirs in southwestern Kansas and Cherokee Group reservoirs in southeastern Kansas. Two demonstration sites operated by different independent oil operators are involved in this project. The Stewart Field is located in Finney County, Kansas and is operated by North American Resources Company. The Nelson Lease is located in Allen County, Kansas, in the N.E. Savonburg Field and is operated by James E. Russell Petroleum, Inc. General topics to be addressed are (1) reservoir management and performance evaluation, (2) waterflood optimization, and (3) the demonstration of recovery processes involving off-the-shelf technologies which can be used to enhance waterflood recovery, increase reserves, and reduce the abandonment rate of these reservoir types. In the Stewart Project, the reservoir management portion of the project conducted during Budget Period I involved performance evaluation. This included (1) reservoir characterization and the development of a reservoir database, (2) volumetric analysis to evaluate production performance, (3) reservoir modeling, (4) laboratory work, (5) identification of operational problems, (6) identification of unrecovered mobile oil and estimation of recovery factors, and (7) identification of the most efficient and economical recovery process. To accomplish these objectives the initial budget period was subdivided into three major tasks. The tasks were (1) geological and engineering analysis, (2) laboratory testing, and (3) unitization. Due to the presence of different operators within the field, it was necessary to unitize the field in order to demonstrate a field-wide improved recovery process. This work was completed and the project moved into Budget Period 2. Budget Period 2 objectives consisted of the design, construction, and operation of a field-wide waterflood utilizing state-of-the-art, off-the-shelf technologies in an attempt to optimize secondary oil recovery. To accomplish these objectives the second budget period was subdivided into five major tasks. The tasks were (1) design and construction of a waterflood plant, (2) design and construction of a water injection system, (3) design and construction of tank battery consolidation and gathering system, (4) initiation of waterflood operations and reservoir management, and (5) technology transfer. In the Savonburg Project, the reservoir management portion involves performance evaluation. This work included (1) reservoir characterization and the development of a reservoir database, (2) identification of operational problems, (3) identification of near wellbore problems such as plugging caused from poor water quality, (4) identification of unrecovered mobile oil and estimation of recovery factors, and (5) preliminary identification of the most efficient and economical recovery process i.e., polymer augmented waterflooding or infill drilling (vertical or horizontal wells). To accomplish this work the initial budget period was subdivided into four major tasks. The tasks included (1) geological and engineering analysis, (2) waterplant optimization, (3) wellbore cleanup and pattern changes, and (4) field operations. This work was completed and the project has moved into Budget Period 2. The Budget Period 2 objectives consisted of continual optimization of this mature waterflood in an attempt to optimize secondary and tertiary oil recovery. To accomplish these objectives the second budget period was subdivided into six major tasks. The tasks were (1) waterplant development, (2) profile modification treatments, (3) pattern changes, new wells and wellbore cleanups, (4) reservoir development (polymer flooding), (5) field operations, and (6) technology transfer.

  17. INCREASING HEAVY OIL RESERVES IN THE WILMINGTON OIL FIELD THROUGH ADVANCED RESERVOIR CHARACTERIZATION AND THERMAL PRODUCTION TECHNOLOGIES

    SciTech Connect (OSTI)

    Scott Hara

    2000-02-18

    The project involves using advanced reservoir characterization and thermal production technologies to improve thermal recovery techniques and lower operating and capital costs in a slope and basin clastic (SBC) reservoir in the Wilmington field, Los Angeles Co., CA. Through March 1999, project work has been completed related to data preparation, basic reservoir engineering, developing a deterministic three dimensional (3-D) geologic model, a 3-D deterministic reservoir simulation model, and a rock-log model, well drilling and completions, and surface facilities. Work is continuing on the stochastic geologic model, developing a 3-D stochastic thermal reservoir simulation model of the Fault Block IIA Tar (Tar II-A) Zone, and operational work and research studies to prevent thermal-related formation compaction. Thermal-related formation compaction is a concern of the project team due to observed surface subsidence in the local area above the steamflood project. Last quarter on January 12, the steamflood project lost its inexpensive steam source from the Harbor Cogeneration Plant as a result of the recent deregulation of electrical power rates in California. An operational plan was developed and implemented to mitigate the effects of the two situations. Seven water injection wells were placed in service in November and December 1998 on the flanks of the Phase 1 steamflood area to pressure up the reservoir to fill up the existing steam chest. Intensive reservoir engineering and geomechanics studies are continuing to determine the best ways to shut down the steamflood operations in Fault Block II while minimizing any future surface subsidence. The new 3-D deterministic thermal reservoir simulator model is being used to provide sensitivity cases to optimize production, steam injection, future flank cold water injection and reservoir temperature and pressure. According to the model, reservoir fill up of the steam chest at the current injection rate of 28,000 BPD and gross and net oil production rates of 7,700 BPD and 750 BOPD (injection to production ratio of 4) will occur in October 1999. At that time, the reservoir should act more like a waterflood and production and cold water injection can be operated at lower net injection rates to be determined. Modeling runs developed this quarter found that varying individual well injection rates to meet added production and local pressure problems by sub-zone could reduce steam chest fill-up by up to one month.

  18. INCREASING HEAVY OIL RESERVES IN THE WILMINGTON OIL FIELD THROUGH ADVANCED RESERVOIR CHARACTERIZATION AND THERMAL PRODUCTION TECHNOLOGIES

    SciTech Connect (OSTI)

    Scott Hara

    2002-04-30

    The project involves using advanced reservoir characterization and thermal production technologies to improve thermal recovery techniques and lower operating and capital costs in a slope and basin clastic (SBC) reservoir in the Wilmington field, Los Angeles Co., Calif. Through December 2001, project work has been completed on the following activities: data preparation; basic reservoir engineering; developing a deterministic three dimensional (3-D) geologic model, a 3-D deterministic reservoir simulation model and a rock-log model; well drilling and completions; and surface facilities on the Fault Block II-A Tar Zone (Tar II-A). Work is continuing on research to understand the geochemistry and process regarding the sand consolidation well completion technique, final reservoir tracer work, operational work and research studies to prevent thermal-related formation compaction in the Tar II-A steamflood area, and operational work on the Tar V steamflood pilot and Tar II-A post-steamflood projects. During the First Quarter 2002, the project team developed an accelerated oil recovery and reservoir cooling plan for the Tar II-A post-steamflood project and began implementing the associated well work in March. The Tar V pilot steamflood project will be converted to post-steamflood cold water injection in April 2002. The Tar II-A post-steamflood operation started in February 1999 and steam chest fillup occurred in September-October 1999. The targeted reservoir pressures in the ''T'' and ''D'' sands are maintained at 90 {+-} 5% hydrostatic levels by controlling water injection and gross fluid production and through the bimonthly pressure monitoring program enacted at the start of the post-steamflood phase. Most of the 2001 well work resulted in maintaining oil and gross fluid production and water injection rates. Reservoir pressures in the ''T'' and ''D'' sands are at 88% and 91% hydrostatic levels, respectively. Well work during the first quarter and plans for 2002 are described in the Reservoir Management section. The steamflood operation in the Tar V pilot project is mature and profitable. Recent production performance has been below projections because of wellbore mechanical limitations that have been addressed during this quarter. As the fluid production temperatures were beginning to exceed 350 F, our self-imposed temperature limit, the pilot steamflood was converted to a hot waterflood project in June 2001 and will be converted to cold water injection next quarter.

  19. Dependence of waterflood remaining oil saturation on relative permeability, capillary pressure, and reservoir parameters in mixed wet, turbidite sands

    SciTech Connect (OSTI)

    Hirasaki, G.J.

    1995-12-31

    The dependence of waterflood oil recovery on relative permeability, capillary pressure, and reservoir parameters was investigated by numerical simulation. The relative permeability and capillary pressure curves were based on laboratory measurements on unconsolidated sands and were evaluated for water-wet and mixed wet states. The reservoir model was a prototype turbidite sand with a range of thickness and permeability values. The economic oil recovery was based on an economic limit water cut of 50%. The remaining oil saturation in the swept region for the water-wet cases was close to the residual oil saturation. The remaining oil saturation of the mixed wet cases ranged from low values near the residual oil saturation to far above the residual oil saturation. It is dependent on the reservoir parameters that govern: (1) the vertical {open_quotes}film surface drainage{close_quotes} of oil by gravity, (2) accumulation of a high oil saturation and thus a high relative permeability under the cap rock, (3) updip migration of the oil that accumulated under the cap rock. The dependence on the reservoir parameters can be summarized by dimensionless groups. There is a dimensionless time for the vertical displacement of oil by gravity. The accumulation of a high oil saturation under the cap rock is dependent on the ratio of the capillary transition zone and the sand thickness. The updip migration is dependent on a combination of the gravity number and the end point mobility ratio.

  20. Improved oil recovery in fluvial dominated reservoirs of Kansas--near-term. Annual report

    SciTech Connect (OSTI)

    Green, D.W.; Willhite, G.P.; Walton, A.; Schoeling, L.; Reynolds, R.; Michnick, M.; Watney, L.

    1996-11-01

    Common oil field problems exist in fluvial dominated deltaic reservoirs in Kansas. The problems are poor waterflood sweep efficiency and lack of reservoir management. The poor waterflood sweep efficiency is due to (1) reservoir heterogeneity, (2) channeling of injected water through high permeability zones or fractures, and (3) clogging of injection wells due to solids in the injection water. In many instances the lack of reservoir management results from (1) poor data collection and organization, (2) little or no integrated analysis of existing data by geological and engineering personnel, (3) the presence of multiple operators within the field, and (4) not identifying optimum recovery techniques. Two demonstration sites operated by different independent oil operators are involved in this project. The Stewart Field is located in Finney County, Kansas and is operated by North American Resources Company. This field was in the latter stage of primary production at the beginning of this project and is currently being waterflooded as a result of this project. The Nelson Lease (an existing waterflood) is located in Allen County, Kansas, in the N.E. Savonburg Field and is operated by James E. Russell Petroleum, Inc. The objective is to increase recovery efficiency and economics in these type of reservoirs. The technologies being applied to increase waterflood sweep efficiency are (1) in situ permeability modification treatments, (2) infill drilling, (3) pattern changes, and (4) air flotation to improve water quality. The technologies being applied to improve reservoir management are (1) database development, (2) reservoir simulation, (3) transient testing, (4) database management and (5) integrated geological and engineering analysis. Results of these two field projects are discussed.

  1. Improved Oil Recovery In Fluvial Dominated Deltaic Reservoirs of Kansas - Near Term

    SciTech Connect (OSTI)

    Green, Don W.; McCune, D.; Michnick, M.; Reynolds, R.; Walton, A.; Watney, L.; Willhite, G. Paul

    1999-01-14

    Common oil field problems exist in fluvial dominated deltaic reservoirs in Kansas. The problems are poor waterflood sweep efficiency and lack of reservoir management. The poor waterflood sweep efficiency is due to (1) reservoir heterogeneity, (2) channeling of injected water through high permeability zones or fractures, and (3) clogging of injection wells due to solids in the injection water. In many instances the lack of reservoir management results from (1) poor data collection and organization, (2) little or no integrated analysis of existing data by geological and engineering personnel, (3) the presence of multiple operators within the field, and (4) not identifying optimum recovery techniques. Two demonstration sites operated by different independent oil operators are involved in this project. The Stewart Field is located in Finney County, Kansas and is operated by PetroSantander, Inc. This field was in the latter stage of primary production at the beginning of this project and is currently being waterflooded as a result of this project. The Nelson Lease (an existing waterflood) is located in Allen County, Kansas, in the N.E. Savonburg Field and is operated by James E. Russell Petroleum, Inc. The objective is to increase recovery efficiency and economics in these types of reservoirs. The technologies being applied to increase waterflood sweep efficiency are (1) in situ permeability modification treatments, (2) infill drilling, (3) pattern changes, and (4) air flotation to improve water quality. The technologies being applied to improve reservoir management are (1) database development, (2) reservoir simulation, (3) transient testing, (4) database management, and (5) integrated geological and engineering analysis.

  2. ,"New Mexico Crude Oil Reserves in Nonproducing Reservoirs (Million Barrels)"

    U.S. Energy Information Administration (EIA) Indexed Site

    Reserves in Nonproducing Reservoirs (Million Barrels)" ,"Click worksheet name or tab at bottom for data" ,"Worksheet Name","Description","# Of Series","Frequency","Latest Data for" ,"Data 1","New Mexico Crude Oil Reserves in Nonproducing Reservoirs (Million Barrels)",1,"Annual",2014 ,"Release Date:","11/19/2015" ,"Next Release Date:","12/31/2016" ,"Excel

  3. ,"U.S. Federal Offshore Crude Oil Reserves in Nonproducing Reservoirs (Million Barrels)"

    U.S. Energy Information Administration (EIA) Indexed Site

    Reserves in Nonproducing Reservoirs (Million Barrels)" ,"Click worksheet name or tab at bottom for data" ,"Worksheet Name","Description","# Of Series","Frequency","Latest Data for" ,"Data 1","U.S. Federal Offshore Crude Oil Reserves in Nonproducing Reservoirs (Million Barrels)",1,"Annual",2014 ,"Release Date:","11/19/2015" ,"Next Release Date:","12/31/2016"

  4. ,"U.S. Total Crude Oil Reserves in Nonproducing Reservoirs (Million Barrels)"

    U.S. Energy Information Administration (EIA) Indexed Site

    Reserves in Nonproducing Reservoirs (Million Barrels)" ,"Click worksheet name or tab at bottom for data" ,"Worksheet Name","Description","# Of Series","Frequency","Latest Data for" ,"Data 1","U.S. Total Crude Oil Reserves in Nonproducing Reservoirs (Million Barrels)",1,"Annual",2014 ,"Release Date:","11/19/2015" ,"Next Release Date:","12/31/2016" ,"Excel

  5. Advanced Oil Recovery Technologies for Improved Recovery from Slope Basin Clastic Reservoirs, Nash Draw Brushy Canyon Pool, Eddy County, NM

    SciTech Connect (OSTI)

    Mark B. Murphy

    2005-09-30

    The Nash Draw Brushy Canyon Pool in Eddy County New Mexico was a cost-shared field demonstration project in the U.S. Department of Energy Class III Program. A major goal of the Class III Program was to stimulate the use of advanced technologies to increase ultimate recovery from slope-basin clastic reservoirs. Advanced characterization techniques were used at the Nash Draw Pool (NDP) project to develop reservoir management strategies for optimizing oil recovery from this Delaware reservoir. The objective of the project was to demonstrate that a development program, which was based on advanced reservoir management methods, could significantly improve oil recovery at the NDP. Initial goals were (1) to demonstrate that an advanced development drilling and pressure maintenance program can significantly improve oil recovery compared to existing technology applications and (2) to transfer these advanced methodologies to other oil and gas producers. Analysis, interpretation, and integration of recently acquired geological, geophysical, and engineering data revealed that the initial reservoir characterization was too simplistic to capture the critical features of this complex formation. Contrary to the initial characterization, a new reservoir description evolved that provided sufficient detail regarding the complexity of the Brushy Canyon interval at Nash Draw. This new reservoir description was used as a risk reduction tool to identify 'sweet spots' for a development drilling program as well as to evaluate pressure maintenance strategies. The reservoir characterization, geological modeling, 3-D seismic interpretation, and simulation studies have provided a detailed model of the Brushy Canyon zones. This model was used to predict the success of different reservoir management scenarios and to aid in determining the most favorable combination of targeted drilling, pressure maintenance, well stimulation, and well spacing to improve recovery from this reservoir. An Advanced Log Analysis technique developed from the NDP project has proven useful in defining additional productive zones and refining completion techniques. This program proved to be especially helpful in locating and evaluating potential recompletion intervals, which has resulted in low development costs with only small incremental increases in lifting costs. To develop additional reserves at lower costs, zones behind pipe in existing wells were evaluated using techniques developed for the Brushy Canyon interval. These techniques were used to complete uphole zones in thirteen of the NDP wells. A total of 14 recompletions were done: four during 1999, four during 2000, two during 2001, and four during 2002-2003. These workovers added reserves of 332,304 barrels of oil (BO) and 640,363 MCFG (thousand cubic feet of gas) at an overall weighted average development cost of $1.87 per BOE (barrel of oil equivalent). A pressure maintenance pilot project in a developed area of the field was not conducted because the pilot area was pressure depleted, and the reservoir in that area was found to be compartmentalized and discontinuous. Economic analyses and simulation studies indicated that immiscible injection of lean hydrocarbon gas for pressure maintenance was not warranted at the NDP and would need to be considered for implementation in similar fields very soon after production has started. Simulation studies suggested that the injection of miscible carbon dioxide (CO{sub 2}) could recover significant quantities of oil at the NDP, but a source of low-cost CO{sub 2} was not available in the area. Results from the project indicated that further development will be under playa lakes and potash areas that were beyond the regions covered by well control and are not accessible with vertical wells. These areas, covered by 3-D seismic surveys that were obtained as part of the project, were accessed with combinations of deviated/horizontal wells. Three directional/horizontal wells have been drilled and completed to develop reserves under surface-restricted areas and potash mines. The third well has not been on production long enough for an accurate assessment but initial results from it are encouraging. Cumulative production from the first two wells through August 31, 2005 was 235,039 BO, 816,592 MCFG and 310,333 barrels of water (BW). Total estimated reserves from all three of the horizontal wells are 878,135 BO and 3.87 BCFG. The ratio of net revenue to cost for the first two wells is approximately 2.9 to 1 for an oil price of $30 per barrel that existed when the wells were drilled. Based on recent pricing trends, a detailed reserve study for the project was performed that assumed an oil price of $40 per barrel and a gas price of $7 per MCFG. These results show that this project has acceptable economics and similar projects can be economically developed as long as oil and gas prices remain over $30 per BOE.

  6. Oil recovery enhancement from fractured, low permeability reservoirs. Annual report 1990--1991, Part 1

    SciTech Connect (OSTI)

    Poston, S.W.

    1991-12-31

    Joint funding by the Department of Energy and the State of Texas has Permitted a three year, multi-disciplinary investigation to enhance oil recovery from a dual porosity, fractured, low matrix permeability oil reservoir to be initiated. The Austin Chalk producing horizon trending thru the median of Texas has been identified as the candidate for analysis. Ultimate primary recovery of oil from the Austin Chalk is very low because of two major technological problems. The commercial oil producing rate is based on the wellbore encountering a significant number of natural fractures. The prediction of the location and frequency of natural fractures at any particular region in the subsurface is problematical at this time, unless extensive and expensive seismic work is conducted. A major portion of the oil remains in the low permeability matrix blocks after depletion because there are no methods currently available to the industry to mobilize this bypassed oil. The following multi-faceted study is aimed to develop new methods to increase oil and gas recovery from the Austin Chalk producing trend. These methods may involve new geological and geophysical interpretation methods, improved ways to study production decline curves or the application of a new enhanced oil recovery technique. The efforts for the second year may be summarized as one of coalescing the initial concepts developed during the initial phase to more in depth analyses. Accomplishments are predicting natural fractures; relating recovery to well-log signatures; development of the EOR imbibition process; mathematical modeling; and field test.

  7. U.S. Total Crude Oil Reserves in Nonproducing Reservoirs (Million Barrels)

    U.S. Energy Information Administration (EIA) Indexed Site

    Crude Oil Reserves in Nonproducing Reservoirs (Million Barrels) U.S. Total Crude Oil Reserves in Nonproducing Reservoirs (Million Barrels) Decade Year-0 Year-1 Year-2 Year-3 Year-4 Year-5 Year-6 Year-7 Year-8 Year-9 1990's 3,474 3,755 4,147 4,206 2000's 4,019 5,195 5,271 5,580 5,143 5,691 5,174 5,455 5,400 6,015 2010's 6,980 9,049 11,884 13,200 14,816 - = No Data Reported; -- = Not Applicable; NA = Not Available; W = Withheld to avoid disclosure of individual company data. Release Date:

  8. Improved oil recovery in fluvial dominated deltaic reservoirs of Kansas - Near-term, Class I

    SciTech Connect (OSTI)

    Green, D.W.; Willhite, G.P.; Reynolds, Rodney R.; McCune, A. Dwayne; Michnick, Michael J.; Walton, Anthony W.; Watney, W. Lynn

    2000-06-08

    This project involved two demonstration projects, one in a Marrow reservoir located in the southwestern part of the state and the second in the Cherokee Group in eastern Kansas. Morrow reservoirs of western Kansas are still actively being explored and constitute an important resource in Kansas. Cumulative oil production from the Morrow in Kansas is over 400,000,000 bbls. Much of the production from the Morrow is still in the primary stage and has not reached the mature declining state of that in the Cherokee. The Cherokee Group has produced about 1 billion bbls of oil since the first commercial production began over a century ago. It is a billion-barrel plus resource that is distributed over a large number of fields and small production units. Many of the reservoirs are operated close to the economic limit, although the small units and low production per well are offset by low costs associated with the shallow nature of the reservoirs (less than 1000 ft. deep).

  9. Geochemical character and origin of oils in Ordovician reservoir rock, Illinois and Indiana, USA

    SciTech Connect (OSTI)

    Guthrie, J.M.; Pratt, L.M.

    1995-11-01

    Twenty-three oils produced from reservoirs within the Ordovician Galena Group (Trenton equivalent) and one oil from the Mississippian Ste. Genevieve Limestone in the Illinois and Indiana portions of the Illinois basin are characterized. Two end-member oil groups (1) and (2) and one intermediate group (1A) are identified using conventional carbon isotopic analysis of whole and fractionated oils, gas chromatography (GC) of saturated hydrocarbon fractions, isotope-ratio-monitoring gas chromatography/mass spectrometry (irm-GC/MS) of n-alkanes ranging from C{sub 15} to C{sub 25}, and gas chromatography/mass spectrometry (GC/MS) of the aromatic hydrocarbon fractions. Group 1 is characterized by high odd-carbon predominance in mid-chain n-alkanes (C{sub 15}-C{sub 19}), low abundance Of C{sub 20+}, n-alkanes, and an absence of pristane and phytane. Group IA is characterized by slightly lower odd-carbon predominance of mid-chain n-alkanes, greater abundance of C{sub 20+} n-alkanes compared to group 1, and no pristane and phytane. Conventional correlations of oil to source rock based on carbon isotopic-type curves and hopane (m/z 191) and sterane (m/z 217) distributions are of limited use in distinguishing Ordovician-reservoired oil groups and determining their origin. Oil to source rock correlations using the distribution and carbon isotopic composition of n-alkanes and the m/z 133 chromatograms of n-alkylarenes show that groups 1 and 1A originated from strata of the Upper Ordovician Galena Group. Group 2 either originated solely from the Upper Ordovician Maquoketa Group or from a mixture of oils generated from the Maquoketa Group and the Galena Group. The Mississippian-reservoired oil most likely originated from the Devonian New Albany Group. The use of GC, irm-GC/MS, and GC/MS illustrates the value of integrated molecular and isotopic approaches for correlating oil groups with source rocks.

  10. Evaluation of Reservoir Wettability and its Effect on Oil Recovery,10/96,659,264

    Office of Scientific and Technical Information (OSTI)

    EVALUATION OF RESERVOIR WETTABILITY AND ITS EFFECT ON OIL RECOVERY First Annual Report by Jill S. Buckley Work Performed under Cooperative Agreement Number DE-FC22-96ID13421 Reporting Period: July 1, 1996 - June 30, 1997 Prepared for U.S. Department of Energy Assistant Secretary for Fossil Energy Jerry Casteel, Project Manager National Petroleum Technology Center P.O. Box 3628 Tulsa OK 74101 Prepared by Petroleum Recovery Research Center New Mexico Institute of Mining and Technology 801 Leroy

  11. INCREASING HEAVY OIL RESERVES IN THE WILMINGTON OIL FIELD THROUGH ADVANCED RESERVOIR CHARACTERIZATION AND THERMAL PRODUCTION TECHNOLOGIES

    SciTech Connect (OSTI)

    Scott Hara

    2001-05-08

    The project involves using advanced reservoir characterization and thermal production technologies to improve thermal recovery techniques and lower operating and capital costs in a slope and basin clastic (SBC) reservoir in the Wilmington field, Los Angeles Co., CA. Through March 2001, project work has been completed on the following activities: data preparation; basic reservoir engineering; developing a deterministic three dimensional (3-D) geologic model, a 3-D deterministic reservoir simulation model and a rock-log model; well drilling and completions; and surface facilities on the Fault Block II-A Tar Zone (Tar II-A). Work is continuing on research to understand the geochemistry and process regarding the sand consolidation well completion technique, final reservoir tracer work, operational work and research studies to prevent thermal-related formation compaction in the Tar II-A steamflood area, and operational work on the Tar V steamflood pilot and Tar II-A post-steamflood projects. The project team spent the Second Quarter 2001 performing well work and reservoir surveillance on the Tar II-A post-steamflood project. The Tar II-A steamflood reservoirs have been operated over fifteen months at relatively stable pressures, due in large part to the bimonthly pressure monitoring program enacted at the start of the post-steamflood phase in January 1999. Starting in the Fourth Quarter 2000, the project team has ramped up activity to increase production and injection. This work will continue through 2001 as described in the Operational Management section. Expanding thermal recovery operations to other sections of the Wilmington Oil Field, including the Tar V horizontal well pilot steamflood project, is a critical part of the City of Long Beach and Tidelands Oil Production Company's development strategy for the field. The current steamflood operations in the Tar V pilot are economical, but recent performance is below projections because of wellbore mechanical limitations that are being addressed in 2001. Much of the second quarter was spent writing DOE annual and quarterly reports to stay current with contract requirements.

  12. INCREASING HEAVY OIL RESERVES IN THE WILMINGTON OIL FIELD THROUGH ADVANCED RESERVOIR CHARACTERIZATION AND THERMAL PRODUCTION TECHNOLOGIES

    SciTech Connect (OSTI)

    Scott Hara

    2001-11-01

    The project involves using advanced reservoir characterization and thermal production technologies to improve thermal recovery techniques and lower operating and capital costs in a slope and basin clastic (SBC) reservoir in the Wilmington field, Los Angeles Co., Calif. Through June 2001, project work has been completed on the following activities: data preparation; basic reservoir engineering; developing a deterministic three dimensional (3-D) geologic model, a 3-D deterministic reservoir simulation model and a rock-log model; well drilling and completions; and surface facilities on the Fault Block II-A Tar Zone (Tar II-A). Work is continuing on research to understand the geochemistry and process regarding the sand consolidation well completion technique, final reservoir tracer work, operational work and research studies to prevent thermal-related formation compaction in the Tar II-A steamflood area, and operational work on the Tar V steamflood pilot and Tar II-A post-steamflood projects. The project team spent the Third Quarter 2001 performing well work and reservoir surveillance on the Tar II-A post-steamflood project. The Tar II-A post-steamflood operation started in February 1999 and steam chest fillup occurred in September-October 1999. The targeted reservoir pressures in the ''T'' and ''D'' sands are maintained at 90 {+-} 5% hydrostatic levels by controlling water injection and gross fluid production and through the bimonthly pressure monitoring program enacted at the start of the post-steamflood phase. The project team ramped up well work activity from October 2000 to September 2001 to increase production and injection. This work will continue through 2001 as described in the Operational Management section. Expanding thermal recovery operations to other sections of the Wilmington Oil Field, including the Tar V horizontal well pilot steamflood project, is a critical part of the City of Long Beach and Tidelands Oil Production Company's development strategy for the field. The current steamflood operations in the Tar V pilot are economical, but recent performance is below projections because of wellbore mechanical limitations that are being addressed in 2001.

  13. INCREASING HEAVY OIL RESERVES IN THE WILMINGTON OIL FIELD THROUGH ADVANCED RESERVOIR CHARACTERIZATION AND THERMAL PRODUCTION TECHNOLOGIES

    SciTech Connect (OSTI)

    Scott Hara

    2002-01-31

    The project involves using advanced reservoir characterization and thermal production technologies to improve thermal recovery techniques and lower operating and capital costs in a slope and basin clastic (SBC) reservoir in the Wilmington field, Los Angeles Co., Calif. Through September 2001, project work has been completed on the following activities: data preparation; basic reservoir engineering; developing a deterministic three dimensional (3-D) geologic model, a 3-D deterministic reservoir simulation model and a rock-log model; well drilling and completions; and surface facilities on the Fault Block II-A Tar Zone (Tar II-A). Work is continuing on research to understand the geochemistry and process regarding the sand consolidation well completion technique, final reservoir tracer work, operational work and research studies to prevent thermal-related formation compaction in the Tar II-A steamflood area, and operational work on the Tar V steamflood pilot and Tar II-A post-steamflood projects. The project team spent the Fourth Quarter 2001 performing routine well work and reservoir surveillance on the Tar II-A post-steamflood and Tar V pilot steamflood projects. The Tar II-A post-steamflood operation started in February 1999 and steam chest fillup occurred in September-October 1999. The targeted reservoir pressures in the ''T'' and ''D'' sands are maintained at 90 {+-} 5% hydrostatic levels by controlling water injection and gross fluid production and through the bimonthly pressure monitoring program enacted at the start of the post-steamflood phase. The project team ramped up well work activity from October 2000 through November 2001 to increase production and injection. In December, water injection well FW-88 was plug and abandoned and replaced by new well FW-295 into the ''D'' sands to accommodate the Port of Long Beach at their expense. Well workovers are planned for 2002 as described in the Operational Management section. Expanding thermal recovery operations to other sections of the Wilmington Oil Field, including the Tar V horizontal well pilot steamflood project, is a critical part of the City of Long Beach and Tidelands Oil Production Company's development strategy for the field. The steamflood operation in the Tar V pilot project is mature and profitable. Recent production performance is below projections because of wellbore mechanical limitations that were being addressed in 2001. As the fluid production is hot, the pilot steamflood was converted to a hot waterflood project in June 2001.

  14. Increasing waterflood reserves in the Wilmington oil field through improved reservoir characterization and reservoir management. [Quarterly report], October 1, 1995--December 31, 1995

    SciTech Connect (OSTI)

    Sullivan, D.; Clarke, D.; Walker, S.; Phillips, C.; Nguyen, J.; Moos, D.; Tagbor, K.

    1996-01-23

    The main objective of this project is the transfer of technologies, methodologies, and findings developed and applied in this project to other operators of Slope and Basin Clastic Reservoirs. This project will study methods to identify sands with high remaining oil saturation and to recomplete existing wells using advanced completion technology. The identification of the sands with high remaining oil saturation will be accomplished by developing a deterministic three dimensional (3-D) geologic model and by using a state of the art reservoir management computer software. The wells identified by the geologic and reservoir engineering work as having the best potential will be logged with a pulsed acoustic cased-hole logging tool. The application of the logging tools will be optimized in the lab by developing a rock-log model. This rock-log model will allow us to convert shear wave velocity measured through casing into effective porosity and hydrocarbon saturation. The wells that are shown to have the best oil production potential will be recompleted. The recompletions will be optimized by evaluating short radius and ultra-short radius lateral recompletions as well as other techniques. Technical progress is reported for the following tasks; reservoir characterization, reservoir engineering; deterministic (3-D) geologic modeling; pulsed acoustic logging; and technology transfer.

  15. Increasing waterflood reserves in the Wilmington Oil Field through improved reservoir characterization and reservoir management. Annual report, March 21, 1995--March 20, 1996

    SciTech Connect (OSTI)

    Sullivan, D.; Clarke, D.; Walker, S.; Phillips, C.; Nguyen, J.; Moos, D.; Tagbor, K.

    1997-08-01

    This project uses advanced reservoir characterization tools, including the pulsed acoustic cased-hole logging tool, geologic three- dimensional (3-D) modeling software, and commercially available reservoir management software to identify sands with remaining high oil saturation following waterflood. Production from the identified high oil saturation sands will be stimulated by recompleting existing production and injection wells in these sands using conventional means as well as short radius and ultra-short radius laterals. Although these reservoirs have been waterflooded over 40 years, researchers have found areas of remaining oil saturation. Areas such as the top sand in the Upper Terminal Zone Fault Block V, the western fault slivers of Upper Terminal Zone Fault Block V, the bottom sands of the Tar Zone Fault Block V, and the eastern edge of Fault Block IV in both the Upper Terminal and Lower Terminal Zones all show significant remaining oil saturation. Each area of interest was uncovered emphasizing a different type of reservoir characterization technique or practice. This was not the original strategy but was necessitated by the different levels of progress in each of the project activities.

  16. 3-D Reservoir and Stochastic Fracture Network Modeling for Enhanced Oil Recovery, Circle Ridge Phosphoria/Tensleep Reservoir, and River Reservation, Arapaho and Shoshone Tribes, Wyoming

    SciTech Connect (OSTI)

    La Pointe, Paul; Parney, Robert; Eiben, Thorsten; Dunleavy, Mike; Whitney, John; Eubanks, Darrel

    2002-09-09

    The goal of this project is to improve the recovery of oil from the Circle Ridge Oilfield, located on the Wind River Reservation in Wyoming, through an innovative integration of matrix characterization, structural reconstruction, and the characterization of the fracturing in the reservoir through the use of discrete fracture network models.

  17. INCREASING HEAVY OIL RESERVES IN THE WILMINGTON OIL FIELD THROUGH ADVANCED RESERVOIR CHARACTERIZATION AND THERMAL PRODUCTION TECHNOLOGIES

    SciTech Connect (OSTI)

    Scott Hara

    2000-12-06

    Through December 1999, project work has been completed on the following activities: data preparation; basic reservoir engineering; developing a deterministic three dimensional (3-D) geologic model, a 3-D deterministic reservoir simulation model and a rock-log model; well drilling and completions; and surface facilities on the Fault Block II-A Tar (Tar II-A) Zone. Work is continuing on improving core analysis techniques, final reservoir tracer work, operational work and research studies to prevent thermal-related formation compaction in the Tar II-A steamflood area, and operational work on the Tar V steamflood pilot and Tar II-A post steamflood project. Work was discontinued on the stochastic geologic model and developing a 3-D stochastic thermal reservoir simulation model of the Tar II-A Zone in order to focus the remaining time on using the 3-D deterministic reservoir simulation model to provide alternatives for the Tar II-A post steamflood operations and shale compaction studies. Thermal-related formation compaction is a concern of the project team due to observed surface subsidence in the local area above the Tar II-A steamflood project. On January 12, 1999, the steamflood project lost its inexpensive steam source from the Harbor Cogeneration Plant as a result of the recent deregulation of electrical power rates in California. An operational plan was developed and implemented to mitigate the effects of the two situations by injecting cold water into the flanks of the steamflood. The purpose of flank injection has been to increase and subsequently maintain reservoir pressures at a level that would fill-up the steam chests in the ''T'' and ''D'' sands before they can collapse and cause formation compaction and to prevent the steam chests from reoccurring. A new 3-D deterministic thermal reservoir simulation model was used to provide operations with the necessary water injection rates and allowable production rates by well to minimize future surface subsidence and to accurately project reservoir steam chest fill-up by October 1999. A geomechanics study and a separate reservoir simulation study have been performed to determine the possible indicators of formation compaction, the temperatures at which specific indicators are affected and the projected temperature profiles in the over and underburden shales over a ten year period following steam injection. It was believed that once steam chest fill-up occurred, the reservoir would act more like a waterflood and production and cold water injection could be operated at lower Injection to production ratios (I/P) and net injection rates. In mid-September 1999, net water injection was reduced substantially in the ''D'' sands following steam chest fill-up. This caused reservoir pressures to plummet about 100 psi within six weeks. Starting in late-October 1999, net ''D'' sand injection was increased and reservoir pressures have slowly increased back to steam chest fill-up pressures as of the end of March 2000. When the ''T'' sands reached fill-up, net ''T'' sand injection was lowered only slightly and reservoir pressures stabilized. A more detailed discussion of the operational changes is in the Reservoir Management section of this report. A reservoir pressure monitoring program was developed as part of the poststeamflood reservoir management plan. This bi-monthly sonic fluid level program measures the static fluid levels in all idle wells an average of once a month. The fluid levels have been calibrated for liquid and gas density gradients by comparing a number of them with Amerada bomb pressures taken within a few days. This data allows engineering to respond quickly to rises or declines in reservoir pressure by either increasing injection or production or idling production. Expanding thermal recovery operations to other sections of the Wilmington Oil Field, including the Tar V horizontal well pilot steamflood project, is a critical part of the City of Long Beach and Tidelands Oil Production Company's development strategy for the field. The current thermal operations in the Wilm

  18. QUANTITATIVE METHODS FOR RESERVOIR CHARACTERIZATION AND IMPROVED RECOVERY: APPLICATION TO HEAVY OIL SANDS

    SciTech Connect (OSTI)

    James W. Castle; Fred J. Molz; Ronald W. Falta; Cynthia L. Dinwiddie; Scott E. Brame; Robert A. Bridges

    2002-10-30

    Improved prediction of interwell reservoir heterogeneity has the potential to increase productivity and to reduce recovery cost for California's heavy oil sands, which contain approximately 2.3 billion barrels of remaining reserves in the Temblor Formation and in other formations of the San Joaquin Valley. This investigation involves application of advanced analytical property-distribution methods conditioned to continuous outcrop control for improved reservoir characterization and simulation, particularly in heavy oil sands. The investigation was performed in collaboration with Chevron Production Company U.S.A. as an industrial partner, and incorporates data from the Temblor Formation in Chevron's West Coalinga Field. Observations of lateral variability and vertical sequences observed in Temblor Formation outcrops has led to a better understanding of reservoir geology in West Coalinga Field. Based on the characteristics of stratigraphic bounding surfaces in the outcrops, these surfaces were identified in the subsurface using cores and logs. The bounding surfaces were mapped and then used as reference horizons in the reservoir modeling. Facies groups and facies tracts were recognized from outcrops and cores of the Temblor Formation and were applied to defining the stratigraphic framework and facies architecture for building 3D geological models. The following facies tracts were recognized: incised valley, estuarine, tide- to wave-dominated shoreline, diatomite, and subtidal. A new minipermeameter probe, which has important advantages over previous methods of measuring outcrop permeability, was developed during this project. The device, which measures permeability at the distal end of a small drillhole, avoids surface weathering effects and provides a superior seal compared with previous methods for measuring outcrop permeability. The new probe was used successfully for obtaining a high-quality permeability data set from an outcrop in southern Utah. Results obtained from analyzing the fractal structure of permeability data collected from the southern Utah outcrop and from core permeability data provided by Chevron from West Coalinga Field were used in distributing permeability values in 3D reservoir models. Spectral analyses and the Double Trace Moment method (Lavallee et al., 1991) were used to analyze the scaling and multifractality of permeability data from cores from West Coalinga Field. T2VOC, which is a numerical flow simulator capable of modeling multiphase, multi-component, nonisothermal flow, was used to model steam injection and oil production for a portion of section 36D in West Coalinga Field. The layer structure and permeability distributions of different models, including facies group, facies tract, and fractal permeability models, were incorporated into the numerical flow simulator. The injection and production histories of wells in the study area were modeled, including shutdowns and the occasional conversion of production wells to steam injection wells. The framework provided by facies groups provides a more realistic representation of the reservoir conditions than facies tracts, which is revealed by a comparison of the history-matching for the oil production. Permeability distributions obtained using the fractal results predict the high degree of heterogeneity within the reservoir sands of West Coalinga Field. The modeling results indicate that predictions of oil production are strongly influenced by the geologic framework and by the boundary conditions. The permeability data collected from the southern Utah outcrop, support a new concept for representing natural heterogeneity, which is called the fractal/facies concept. This hypothesis is one of the few potentially simplifying concepts to emerge from recent studies of geological heterogeneity. Further investigation of this concept should be done to more fully apply fractal analysis to reservoir modeling and simulation. Additional outcrop permeability data sets and further analysis of the data from distinct facies will be needed in order to fully develop

  19. Dependence of waterflood remaining oil saturation on relative permeability, capillary pressure, and reservoir parameters in mixed-wet turbidite sands

    SciTech Connect (OSTI)

    Hirasaki, G.J.

    1996-05-01

    The dependence of waterflood oil recovery on relative permeability, capillary pressure, and reservoir parameters was investigated by numerical simulation. The relative permeability and capillary pressure curves were based on laboratory measurements on unconsolidated sands. The water-wet case is based on the assumption that the system is water-wet and measurements were made with refined oil. The mixed-wet case assumed that the system is mixed-wet and restored-state measurements were made with crude oil. The reservoir model was a prototype turbidite sand with a range of thickness and permeability values. The economic oil recovery was based on an economic limit water cut of 50%. The remaining oil saturation (ROS) in the swept region for the water-wet cases was close to the residual oil saturation. The ROS of the mixed-wet cases ranged from low values near the residual oil saturation to far above the residual oil saturation. It is dependent on the reservoir parameters that govern (1) the vertical film surface drainage of oil by gravity, (2) accumulation of a high oil saturation and thus a high relative permeability under the caprock, and (3) up-dip migration of the oil that accumulated under the caprock. The dependence on the reservoir parameters can be summarized by dimensionless groups. There is a dimensionless time for the vertical displacement of oil by gravity. The accumulation of a high oil saturation under the caprock is dependent on the ratio of the capillary transition zone and the sand thickness. The updip migration is dependent on a combination of the gravity number and the endpoint mobility ratio.

  20. CO{sub 2} Huff-n-Puff process in a light oil shallow shelf carbonate reservoir. Second quarterly technical progress report, [April 1995--June 1995

    SciTech Connect (OSTI)

    Cole, R.; Prieditis, J.; Vogt, J.; Wehner, S.

    1995-07-11

    The principal objective of the Central Vacuum Unit (CVU) CO{sub 2} Huff-n-Puff (H-n-P) project is to determine the feasibility and practicality of the technology in a waterflooded shallow shelf carbonate environment. The results of parametric simulation of the CO{sub 2} H-n-P process, coupled with the CVU reservoir characterization components will determine if this process is technically and economically feasible for field implementation. The technology transfer objective of the project is to disseminate the knowledge gained through an innovative plan in support of the Department of Energy`s (DOE) objective of increasing domestic oil production and deferring the abandonment of shallow shelf carbonate (SSC) reservoirs. Tasks associated with this objective are carried out in what is considered a timely effort for near-term goals. Technical progress is summarized for; geostatistical realizations; site-specific simulation;waterflood review; and reservoir characterization.

  1. Application of turbidite facies of the Stevens Oil Zone for reservoir management, Elk Hills Field, California

    SciTech Connect (OSTI)

    Reid, S.A.; Thompson, T.W.; McJannet, G.S.

    1996-12-31

    A detailed depositional model for the uppermost sand reservoirs of the Stevens Oil Zone, Elk Hills Field, California, contains three facies: turbidite channel-fill sand bodies, overbank Sandstone and mudstone, and pelagic and hemipelagic siliceous shale. Sand bodies are the primary producing facies and consist of layered, graded sandstone with good permeability. The presence of incipient anticlines with subsea relief in the late Miocene resulted in deposition of lenticular and sinuous sand Was within structurally created channels. Relief of these structural channels was low when the earliest sand bodies were deposited, leading to a wide channel complex bounded by broad overbank deposits of moderate to low permeability. As deposition proceeded, increased structural relief constrained the channels, resulting in narrower sand body width and relatively abrupt channel terminations against very low permeability siliceous shale. With post-Miocene uplift and differential compaction, stratigraphic mounding of sand bodies helped create structural domes such as the 24Z reservoir. Stratigraphic traps including the 26R reservoir were also created. Such traps vary in seal quality from very effective to leaky, depending on the lateral transition from sand bodies to siliceous shale. Application of the Elk Hills turbidity model (1) provides a framework for monitoring production performance in the 24Z and Northwest Stevens waterflood projects; and for tracking gas migration into and out of the 26R reservoir, (2) helps b identify undeveloped locations in the 26R reservoir ideally suited for horizontal wells, (3) has led to the identification of two new production trends in the 29R area, and (4) makes possible the development of exploration plays in western Elk Hills.

  2. Application of turbidite facies of the Stevens Oil Zone for reservoir management, Elk Hills Field, California

    SciTech Connect (OSTI)

    Reid, S.A.; Thompson, T.W. ); McJannet, G.S. )

    1996-01-01

    A detailed depositional model for the uppermost sand reservoirs of the Stevens Oil Zone, Elk Hills Field, California, contains three facies: turbidite channel-fill sand bodies, overbank Sandstone and mudstone, and pelagic and hemipelagic siliceous shale. Sand bodies are the primary producing facies and consist of layered, graded sandstone with good permeability. The presence of incipient anticlines with subsea relief in the late Miocene resulted in deposition of lenticular and sinuous sand Was within structurally created channels. Relief of these structural channels was low when the earliest sand bodies were deposited, leading to a wide channel complex bounded by broad overbank deposits of moderate to low permeability. As deposition proceeded, increased structural relief constrained the channels, resulting in narrower sand body width and relatively abrupt channel terminations against very low permeability siliceous shale. With post-Miocene uplift and differential compaction, stratigraphic mounding of sand bodies helped create structural domes such as the 24Z reservoir. Stratigraphic traps including the 26R reservoir were also created. Such traps vary in seal quality from very effective to leaky, depending on the lateral transition from sand bodies to siliceous shale. Application of the Elk Hills turbidity model (1) provides a framework for monitoring production performance in the 24Z and Northwest Stevens waterflood projects; and for tracking gas migration into and out of the 26R reservoir, (2) helps b identify undeveloped locations in the 26R reservoir ideally suited for horizontal wells, (3) has led to the identification of two new production trends in the 29R area, and (4) makes possible the development of exploration plays in western Elk Hills.

  3. WETTABILITY AND PREDICTION OF OIL RECOVERY FROM RESERVOIRS DEVELOPED WITH MODERN DRILLING AND COMPLETION FLUIDS

    SciTech Connect (OSTI)

    Jill S. Buckley; Norman R. Morrow

    2006-01-01

    The objectives of this project are: (1) to improve understanding of the wettability alteration of mixed-wet rocks that results from contact with the components of synthetic oil-based drilling and completion fluids formulated to meet the needs of arctic drilling; (2) to investigate cleaning methods to reverse the wettability alteration of mixed-wet cores caused by contact with these SBM components; and (3) to develop new approaches to restoration of wetting that will permit the use of cores drilled with SBM formulations for valid studies of reservoir properties.

  4. Class III Mid-Term Project, "Increasing Heavy Oil Reserves in the Wilmington Oil Field Through Advanced Reservoir Characterization and Thermal Production Technologies"

    SciTech Connect (OSTI)

    Scott Hara

    2007-03-31

    The overall objective of this project was to increase heavy oil reserves in slope and basin clastic (SBC) reservoirs through the application of advanced reservoir characterization and thermal production technologies. The project involved improving thermal recovery techniques in the Tar Zone of Fault Blocks II-A and V (Tar II-A and Tar V) of the Wilmington Field in Los Angeles County, near Long Beach, California. A primary objective has been to transfer technology that can be applied in other heavy oil formations of the Wilmington Field and other SBC reservoirs, including those under waterflood. The first budget period addressed several producibility problems in the Tar II-A and Tar V thermal recovery operations that are common in SBC reservoirs. A few of the advanced technologies developed include a three-dimensional (3-D) deterministic geologic model, a 3-D deterministic thermal reservoir simulation model to aid in reservoir management and subsequent post-steamflood development work, and a detailed study on the geochemical interactions between the steam and the formation rocks and fluids. State of the art operational work included drilling and performing a pilot steam injection and production project via four new horizontal wells (2 producers and 2 injectors), implementing a hot water alternating steam (WAS) drive pilot in the existing steamflood area to improve thermal efficiency, installing a 2400-foot insulated, subsurface harbor channel crossing to supply steam to an island location, testing a novel alkaline steam completion technique to control well sanding problems, and starting on an advanced reservoir management system through computer-aided access to production and geologic data to integrate reservoir characterization, engineering, monitoring, and evaluation. The second budget period phase (BP2) continued to implement state-of-the-art operational work to optimize thermal recovery processes, improve well drilling and completion practices, and evaluate the geomechanical characteristics of the producing formations. The objectives were to further improve reservoir characterization of the heterogeneous turbidite sands, test the proficiency of the three-dimensional geologic and thermal reservoir simulation models, identify the high permeability thief zones to reduce water breakthrough and cycling, and analyze the nonuniform distribution of the remaining oil in place. This work resulted in the redevelopment of the Tar II-A and Tar V post-steamflood projects by drilling several new wells and converting idle wells to improve injection sweep efficiency and more effectively drain the remaining oil reserves. Reservoir management work included reducing water cuts, maintaining or increasing oil production, and evaluating and minimizing further thermal-related formation compaction. The BP2 project utilized all the tools and knowledge gained throughout the DOE project to maximize recovery of the oil in place.

  5. ADVANCED OIL RECOVERY TECHNOLOGIES FOR IMPROVED RECOVERY FROM SLOPE BASIN CLASTIC RESERVOIRS, NASH DRAW BRUSHY CANYON POOL, EDDY COUNTY, NM

    SciTech Connect (OSTI)

    Mark B. Murphy

    2001-10-31

    The Nash Draw Brushy Canyon Pool (NDP) in southeast New Mexico is one of the nine projects selected in 1995 by the U.S. Department of Energy (DOE) for participation in the Class III Reservoir Field Demonstration Program. The goals of the DOE cost-shared Class Program are to: (1) extend economic production, (2) increase ultimate recovery, and (3) broaden information exchange and technology application. Reservoirs in the Class III Program are focused on slope basin and deep-basin clastic depositional types. Production at the NDP is from the Brushy Canyon formation, a low-permeability turbidite reservoir in the Delaware Mountain Group of Permian, Guadalupian age. A major challenge in this marginal-quality reservoir is to distinguish oil-productive pay intervals from water-saturated non-pay intervals. Because initial reservoir pressure is only slightly above bubble-point pressure, rapid oil decline rates and high gas/oil ratios are typically observed in the first year of primary production. Limited surface access, caused by the proximity of underground potash mining and surface playa lakes, prohibits development with conventional drilling. Reservoir characterization results obtained to date at the NDP show that a proposed pilot injection area appears to be compartmentalized. Because reservoir discontinuities will reduce effectiveness of a pressure maintenance project, the pilot area will be reconsidered in a more continuous part of the reservoir if such areas have sufficient reservoir pressure. Most importantly, the advanced characterization results are being used to design extended reach/horizontal wells to tap into predicted ''sweet spots'' that are inaccessible with conventional vertical wells. The activity at the NDP during the past year has included the completion of the NDP Well No.36 deviated/horizontal well and the completion of additional zones in three wells, the design of the NDP No.33 directional/horizontal well, The planning and regulatory approval for the north No.-D seismic survey extension and the continued analysis of data.

  6. Improved oil recovery in fluvial dominated deltaic reservoirs of Kansas - near-term. Quarterly report, April 1 - June 30, 1996

    SciTech Connect (OSTI)

    Green, D.W.; Willhite, G.P.; Walton, A.; Schoeling, L.; Reynolds, R.; Michnick, M.; Watney, L.

    1996-07-01

    The objective of this project is to address waterflood problems of the type found in Morrow sandstone reservoirs in southwestern Kansas and Cherokee Group reservoirs in southeastern Kansas. Two demonstration sites, Stewart Field, and Savonburg Field, operated by different independent oil operators are involved in this project. General topics to be addressed are: (1) reservoir management and performance evaluation; (2) waterflood optimization; and (3) the demonstration of recovery processes involving off-the-shelf technologies which can be used to enhance waterflood recovery, increase reserves, and reduce the abandonment rate of these reservoir types. For the Stewart Field project, work is summarized for the last quarter on waterflood operations and reservoir management. For the Savonburg Field project, work on water plant development, and pattern changes and wellbore cleanup are briefly described.

  7. Improved oil recovery in fluvial dominated deltaic reservoirs of Kansas -- Near term. Quarterly report, June 30--September 30, 1995

    SciTech Connect (OSTI)

    Green, D.W.; Willhite, G.P.; Walton, A.; Schoeling, L.; Reynolds, R.; Michnick, M.; Watney, L.

    1995-10-15

    The objective of this project is to address waterflood problems of the type found in Cherokee Group reservoirs in southeastern Kansas and in Morrow sandstone reservoirs in southwestern Kansas. Two demonstration sites operated by different independent oil operators are involved in the project. General topics to be addressed will be (1) reservoir management and performance evaluation; (2) waterflood optimization, and (3) the demonstration of recovery processes involving off-the-shelf technologies which can be used to enhance waterflood recovery, increase reserves, and reduce the abandonment rate of these reservoir types. The reservoir management portion of the project will involve performance evaluation and will include such work as (1) reservoir characterization and the development of a reservoir database, (2) identification of operational problems, (3) identification of near wellbore problems, (4) identification of unrecovered mobile oil and estimation of recovery factors, and (5) identification of the most efficient and economical recovery process. The waterflood optimization portion of the project involves only the Nelson Lease. It will be based on the performance evaluation and will involve (1) design and implementation of a water cleanup system for the waterflood, (2) application of well remedial work such as polymer gel treatments to improve vertical sweep efficiency, and (3) changes in waterflood patterns to increase sweep efficiency. Finally, it is planned to implement an improved recovery process on both field demonstration sites.

  8. ,"Calif--Los Angeles Basin Onshore Crude Oil Reserves in Nonproducing Reservoirs (Million Barrels)"

    U.S. Energy Information Administration (EIA) Indexed Site

    Crude Oil Reserves in Nonproducing Reservoirs (Million Barrels)" ,"Click worksheet name or tab at bottom for data" ,"Worksheet Name","Description","# Of Series","Frequency","Latest Data for" ,"Data 1","Calif--Los Angeles Basin Onshore Crude Oil Reserves in Nonproducing Reservoirs (Million Barrels)",1,"Annual",2014 ,"Release Date:","11/19/2015" ,"Next Release

  9. ,"Calif--San Joaquin Basin Onshore Crude Oil Reserves in Nonproducing Reservoirs (Million Barrels)"

    U.S. Energy Information Administration (EIA) Indexed Site

    Crude Oil Reserves in Nonproducing Reservoirs (Million Barrels)" ,"Click worksheet name or tab at bottom for data" ,"Worksheet Name","Description","# Of Series","Frequency","Latest Data for" ,"Data 1","Calif--San Joaquin Basin Onshore Crude Oil Reserves in Nonproducing Reservoirs (Million Barrels)",1,"Annual",2014 ,"Release Date:","11/19/2015" ,"Next Release

  10. An Integrated Approach to Characterizing Bypassed Oil in Heterogeneous and Fractured Reservoirs Using Partitioning Tracers

    SciTech Connect (OSTI)

    Akhil Datta-Gupta

    2006-12-31

    We explore the use of efficient streamline-based simulation approaches for modeling partitioning interwell tracer tests in hydrocarbon reservoirs. Specifically, we utilize the unique features of streamline models to develop an efficient approach for interpretation and history matching of field tracer response. A critical aspect here is the underdetermined and highly ill-posed nature of the associated inverse problems. We have investigated the relative merits of the traditional history matching ('amplitude inversion') and a novel travel time inversion in terms of robustness of the method and convergence behavior of the solution. We show that the traditional amplitude inversion is orders of magnitude more non-linear and the solution here is likely to get trapped in local minimum, leading to inadequate history match. The proposed travel time inversion is shown to be extremely efficient and robust for practical field applications. The streamline approach is generalized to model water injection in naturally fractured reservoirs through the use of a dual media approach. The fractures and matrix are treated as separate continua that are connected through a transfer function, as in conventional finite difference simulators for modeling fractured systems. A detailed comparison with a commercial finite difference simulator shows very good agreement. Furthermore, an examination of the scaling behavior of the computation time indicates that the streamline approach is likely to result in significant savings for large-scale field applications. We also propose a novel approach to history matching finite-difference models that combines the advantage of the streamline models with the versatility of finite-difference simulation. In our approach, we utilize the streamline-derived sensitivities to facilitate history matching during finite-difference simulation. The use of finite-difference model allows us to account for detailed process physics and compressibility effects. The approach is very fast and avoids much of the subjective judgments and time-consuming trial-and-errors associated with manual history matching. We demonstrate the power and utility of our approach using a synthetic example and two field examples. We have also explored the use of a finite difference reservoir simulator, UTCHEM, for field-scale design and optimization of partitioning interwell tracer tests. The finite-difference model allows us to include detailed physics associated with reactive tracer transport, particularly those related with transverse and cross-streamline mechanisms. We have investigated the potential use of downhole tracer samplers and also the use of natural tracers for the design of partitioning tracer tests. Finally, we discuss several alternative ways of using partitioning interwell tracer tests (PITTs) in oil fields for the calculation of oil saturation, swept pore volume and sweep efficiency, and assess the accuracy of such tests under a variety of reservoir conditions.

  11. Using Biosurfactants Produced from Agriculture Process Waste Streams to Improve Oil Recovery in Fractured Carbonate Reservoirs

    SciTech Connect (OSTI)

    Stephen Johnson; Mehdi Salehi; Karl Eisert; Sandra Fox

    2009-01-07

    This report describes the progress of our research during the first 30 months (10/01/2004 to 03/31/2007) of the original three-year project cycle. The project was terminated early due to DOE budget cuts. This was a joint project between the Tertiary Oil Recovery Project (TORP) at the University of Kansas and the Idaho National Laboratory (INL). The objective was to evaluate the use of low-cost biosurfactants produced from agriculture process waste streams to improve oil recovery in fractured carbonate reservoirs through wettability mediation. Biosurfactant for this project was produced using Bacillus subtilis 21332 and purified potato starch as the growth medium. The INL team produced the biosurfactant and characterized it as surfactin. INL supplied surfactin as required for the tests at KU as well as providing other microbiological services. Interfacial tension (IFT) between Soltrol 130 and both potential benchmark chemical surfactants and crude surfactin was measured over a range of concentrations. The performance of the crude surfactin preparation in reducing IFT was greater than any of the synthetic compounds throughout the concentration range studied but at low concentrations, sodium laureth sulfate (SLS) was closest to the surfactin, and was used as the benchmark in subsequent studies. Core characterization was carried out using both traditional flooding techniques to find porosity and permeability; and NMR/MRI to image cores and identify pore architecture and degree of heterogeneity. A cleaning regime was identified and developed to remove organic materials from cores and crushed carbonate rock. This allowed cores to be fully characterized and returned to a reproducible wettability state when coupled with a crude-oil aging regime. Rapid wettability assessments for crushed matrix material were developed, and used to inform slower Amott wettability tests. Initial static absorption experiments exposed limitations in the use of HPLC and TOC to determine surfactant concentrations. To reliably quantify both benchmark surfactants and surfactin, a surfactant ion-selective electrode was used as an indicator in the potentiometric titration of the anionic surfactants with Hyamine 1622. The wettability change mediated by dilute solutions of a commercial preparation of SLS (STEOL CS-330) and surfactin was assessed using two-phase separation, and water flotation techniques; and surfactant loss due to retention and adsorption on the rock was determined. Qualitative tests indicated that on a molar basis, surfactin is more effective than STEOL CS-330 in altering wettability of crushed Lansing-Kansas City carbonates from oil-wet to water-wet state. Adsorption isotherms of STEOL CS-330 and surfactin on crushed Lansing-Kansas City outcrop and reservoir material showed that surfactin has higher specific adsorption on these oomoldic carbonates. Amott wettability studies confirmed that cleaned cores are mixed-wet, and that the aging procedure renders them oil-wet. Tests of aged cores with no initial water saturation resulted in very little spontaneous oil production, suggesting that water-wet pathways into the matrix are required for wettability change to occur. Further investigation of spontaneous imbibition and forced imbibition of water and surfactant solutions into LKC cores under a variety of conditions--cleaned vs. crude oil-aged; oil saturated vs. initial water saturation; flooded with surfactant vs. not flooded--indicated that in water-wet or intermediate wet cores, sodium laureth sulfate is more effective at enhancing spontaneous imbibition through wettability change. However, in more oil-wet systems, surfactin at the same concentration performs significantly better.

  12. Advanced Oil Recovery Technologies for Improved Recovery from Slope Basin Clastic Reservoirs, Nash Draw Brushy Canyon Pool, Eddy County, New Mexico, Class III

    SciTech Connect (OSTI)

    Murphy, Mark B.

    2002-01-16

    The overall objective of this project was to demonstrate that a development program-based on advanced reservoir management methods-can significantly improve oil recovery at the Nash Draw Pool (NDP). The plan included developing a control area using standard reservoir management techniques and comparing its performance to an area developed using advanced reservoir management methods. Specific goals were (1) to demonstrate that an advanced development drilling and pressure maintenance program can significantly improve oil recovery compared to existing technology applications and (2) to transfer these advanced methodologies to oil and gas producers in the Permian Basin and elsewhere throughout the U.S. oil and gas industry.

  13. Increased Oil Production and Reserves Utilizing Secondary/Terriary Recovery Techniques on Small Reservoirs in the Paradox Basin, Utah

    SciTech Connect (OSTI)

    David E. Eby; Thomas C. Chidsey, Jr.

    1998-04-08

    The primary objective of this project is to enhance domestic petroleum production by demonstration and technology transfer of an advanced oil recovery technology in the Paradox basin, southeastern Utah. If this project can demonstrate technical and economic feasibility, the technique can be applied to about 100 additional small fields in the Paradox basin alone, and result in increased recovery of 150 to 200 million barrels of oil. This project is designed to characterize five shallow-shelf carbonate reservoirs in the Pennsylvanian (Desmoinesian) Paradox Formation and choose the best candidate for a pilot demonstration project for either a waterflood or carbon dioxide-(CO -) 2 flood project. The field demonstration, monitoring of field performance, and associated validation activities will take place in the Paradox basin within the Navajo Nation. Two activities continued this quarter as part of the geological and reservoir characterization of productive carbonate buildups in the Paradox basin: (1) diagenetic characterization of project field reservoirs, and (2) technology transfer.

  14. Advanced reservoir characterization for improved oil recovery in a New Mexico Delaware basin project

    SciTech Connect (OSTI)

    Martin, F.D.; Kendall, R.P.; Whitney, E.M.

    1997-08-01

    The Nash Draw Brushy Canyon Pool in Eddy County, New Mexico is a field demonstration site in the Department of Energy Class III program. The basic problem at the Nash Draw Pool is the low recovery typically observed in similar Delaware fields. By comparing a control area using standard infill drilling techniques to a pilot area developed using advanced reservoir characterization methods, the goal of the project is to demonstrate that advanced technology can significantly improve oil recovery. During the first year of the project, four new producing wells were drilled, serving as data acquisition wells. Vertical seismic profiles and a 3-D seismic survey were acquired to assist in interwell correlations and facies prediction. Limited surface access at the Nash Draw Pool, caused by proximity of underground potash mining and surface playa lakes, limits development with conventional drilling. Combinations of vertical and horizontal wells combined with selective completions are being evaluated to optimize production performance. Based on the production response of similar Delaware fields, pressure maintenance is a likely requirement at the Nash Draw Pool. A detailed reservoir model of pilot area was developed, and enhanced recovery options, including waterflooding, lean gas, and carbon dioxide injection, are being evaluated.

  15. CO{sub 2} Huff-n-Puff process in a light oil shallow shelf carbonate reservoir. Quarterly technical progress report, July--September, 1995

    SciTech Connect (OSTI)

    Cole, R.; Prieditis, J.; Vogt, J. Wehner, S.

    1995-10-15

    The principal objective of the Central Vacuum Unit (CVU) CO{sub 2} Huff-n-Puff (H-n-P) project is to determine the feasibility and practicality of the technology in a waterflooded shallow shelf carbonate environment. The results of parametric simulation of the CO{sub 2} H-n-P process, coupled with the CVU reservoir characterization components will determine if this process is technically and economically feasible for field implementation. The technology transfer objective of the project is to disseminate the knowledge gained through an innovative plan in support of the Department of Energy`s (DOE) objective of increasing domestic oil production and deferring the abandonment of shallow shelf carbonate (SSC) reservoirs. Tasks associated with this objective are carried out in what is considered a timely effort for near-term goals.

  16. INCREASED OIL PRODUCTION AND RESERVES UTILIZING SECONDARY/TERTIARY RECOVERY TECHNIQUES ON SMALL RESERVOIRS IN THE PARADOX BASIN, UTAH

    SciTech Connect (OSTI)

    Thomas C. Chidsey, Jr.

    2002-11-01

    The Paradox Basin of Utah, Colorado, and Arizona contains nearly 100 small oil fields producing from shallow-shelf carbonate buildups or mounds within the Desert Creek zone of the Pennsylvanian (Desmoinesian) Paradox Formation. These fields typically have one to four wells with primary production ranging from 700,000 to 2,000,000 barrels (111,300-318,000 m{sup 3}) of oil per field at a 15 to 20 percent recovery rate. Five fields in southeastern Utah were evaluated for waterflood or carbon-dioxide (CO{sub 2})-miscible flood projects based upon geological characterization and reservoir modeling. Geological characterization on a local scale focused on reservoir heterogeneity, quality, and lateral continuity as well as possible compartmentalization within each of the five project fields. The Desert Creek zone includes three generalized facies belts: (1) open-marine, (2) shallow-shelf and shelf-margin, and (3) intra-shelf, salinity-restricted facies. These deposits have modern analogs near the coasts of the Bahamas, Florida, and Australia, respectively, and outcrop analogs along the San Juan River of southeastern Utah. The analogs display reservoir heterogeneity, flow barriers and baffles, and lithofacies geometry observed in the fields; thus, these properties were incorporated in the reservoir simulation models. Productive carbonate buildups consist of three types: (1) phylloid algal, (2) coralline algal, and (3) bryozoan. Phylloid-algal buildups have a mound-core interval and a supra-mound interval. Hydrocarbons are stratigraphically trapped in porous and permeable lithotypes within the mound-core intervals of the lower part of the buildups and the more heterogeneous supramound intervals. To adequately represent the observed spatial heterogeneities in reservoir properties, the phylloid-algal bafflestones of the mound-core interval and the dolomites of the overlying supra-mound interval were subdivided into ten architecturally distinct lithotypes, each of which exhibits a characteristic set of reservoir properties obtained from outcrop analogs, cores, and geophysical logs. The Anasazi and Runway fields were selected for geostatistical modeling and reservoir compositional simulations. Models and simulations incorporated variations in carbonate lithotypes, porosity, and permeability to accurately predict reservoir responses. History matches tied previous production and reservoir pressure histories so that future reservoir performances could be confidently predicted. The simulation studies showed that despite most of the production being from the mound-core intervals, there were no corresponding decreases in the oil in place in these intervals. This behavior indicates gravity drainage of oil from the supra-mound intervals into the lower mound-core intervals from which the producing wells' major share of production arises. The key to increasing ultimate recovery from these fields (and similar fields in the basin) is to design either waterflood or CO{sub 2}-miscible flood projects capable of forcing oil from high-storage-capacity but low-recovery supra-mound units into the high-recovery mound-core units. Simulation of Anasazi field shows that a CO{sub 2} flood is technically superior to a waterflood and economically feasible. For Anasazi field, an optimized CO{sub 2} flood is predicted to recover a total 4.21 million barrels (0.67 million m3) of oil representing in excess of 89 percent of the original oil in place. For Runway field, the best CO{sub 2} flood is predicted to recover a total of 2.4 million barrels (0.38 million m3) of oil representing 71 percent of the original oil in place. If the CO{sub 2} flood performed as predicted, it is a financially robust process for increasing the reserves in the many small fields in the Paradox Basin. The results can be applied to other fields in the Rocky Mountain region, the Michigan and Illinois Basins, and the Midcontinent.

  17. 3-D RESERVOIR AND STOCHASTIC FRACTURE NETWORK MODELING FOR ENHANCED OIL RECOVERY, CIRCLE RIDGE PHOSPHORIA/TENSLEEP RESERVOIR, WIND RIVER RESERVATION, ARAPAHO AND SHOSHONE TRIBES, WYOMING

    SciTech Connect (OSTI)

    Paul La Pointe; Jan Hermanson; Robert Parney; Thorsten Eiben; Mike Dunleavy; Ken Steele; John Whitney; Darrell Eubanks; Roger Straub

    2002-11-18

    This report describes the results made in fulfillment of contract DE-FG26-00BC15190, ''3-D Reservoir and Stochastic Fracture Network Modeling for Enhanced Oil Recovery, Circle Ridge Phosphoria/Tensleep Reservoir, Wind River Reservation, Arapaho and Shoshone Tribes, Wyoming''. The goal of this project is to improve the recovery of oil from the Tensleep and Phosphoria Formations in Circle Ridge Oilfield, located on the Wind River Reservation in Wyoming, through an innovative integration of matrix characterization, structural reconstruction, and the characterization of the fracturing in the reservoir through the use of discrete fracture network models. Fields in which natural fractures dominate reservoir permeability, such as the Circle Ridge Field, often experience sub-optimal recovery when recovery processes are designed and implemented that do not take advantage of the fracture systems. For example, a conventional waterflood in a main structural block of the Field was implemented and later suspended due to unattractive results. It is estimated that somewhere less than 20% of the OOIP in the Circle Ridge Field have been recovered after more than 50 years' production. Marathon Oil Company identified the Circle Ridge Field as an attractive candidate for several advanced IOR processes that explicitly take advantage of the natural fracture system. These processes require knowledge of the distribution of matrix porosity, permeability and oil saturations; and understanding of where fracturing is likely to be well-developed or poorly developed; how the fracturing may compartmentalize the reservoir; and how smaller, relatively untested subthrust fault blocks may be connected to the main overthrust block. For this reason, the project focused on improving knowledge of the matrix properties, the fault block architecture and to develop a model that could be used to predict fracture intensity, orientation and fluid flow/connectivity properties. Knowledge of matrix properties was greatly extended by calibrating wireline logs from 113 wells with incomplete or older-vintage logging suites to wells with a full suite of modern logs. The model for the fault block architecture was derived by 3D palinspastic reconstruction. This involved field work to construct three new cross-sections at key areas in the Field; creation of horizon and fault surface maps from well penetrations and tops; and numerical modeling to derive the geometry, chronology, fault movement and folding history of the Field through a 3D restoration of the reservoir units to their original undeformed state. The methodology for predicting fracture intensity and orientation variations throughout the Field was accomplished by gathering outcrop and subsurface image log fracture data, and comparing it to the strain field produced by the various folding and faulting events determined through the 3D palinspastic reconstruction. It was found that the strains produced during the initial folding of the Tensleep and Phosphoria Formations corresponded well without both the orientations and relative fracture intensity measured in outcrop and in the subsurface. The results have led to a 15% to 20% increase in estimated matrix pore volume, and to the plan to drill two horizontal drain holes located and oriented based on the modeling results. Marathon Oil is also evaluating alternative tertiary recovery processes based on the quantitative 3D integrated reservoir model.

  18. Revitalizing a mature oil play: Strategies for finding and producing unrecovered oil in Frio Fluvial-Deltaic reservoirs of South Texas. Technical progress report, April 1, 1994--June 30, 1994

    SciTech Connect (OSTI)

    Tyler, N.; Dutton, S.

    1994-06-30

    Advanced reservoir characterization techniques are being applied to selected reservoirs in the Frio Fluvial-Deltaic Sandstone (Vicksburg Fault Zone) trend of South Texas in order to maximize the economic producibility of resources in this mature oil play. More than half of the reservoirs in this depositionally complex play have already been abandoned, and large volumes of oil may remain unproduced unless advanced characterization techniques are applied to define untapped, incompletely drained, and new pool reservoirs as suitable targets for near-term recovery methods. This project is developing interwell-scale geological facies models and assessing engineering attributes of Frio fluvial-deltaic reservoirs in selected fields in order to characterize reservoir architecture, flow unit boundaries, and the controls that these characteristics exert on the location and volume of unrecovered mobile and residual oil. The results of these studies will lead directly to the identification of specific opportunities to exploit these heterogeneous reservoirs for incremental recovery by recompletion and strategic infill drilling. Work during the second project quarter of 1994 focused on continuation of Phase 2 tasks associated with characterizing stratigraphic heterogeneity in selected Frio fluvial-deltaic sandstone reservoirs. Playwide reservoir assessment continued as reservoir engineering data from fields throughout the Frio Fluvial-Deltaic Sandstone trend were grouped within stratigraphic sub-intervals in order to characterize general reservoir heterogeneity, evaluate production behavior, and assess remaining resource potential in middle Frio, lower Frio, and upper Vicksburg reservoir sandstones.

  19. Improved oil recovery in fluvial dominated deltaic reservoirs of Kansas -- Near-term. Quarterly report, January 1--March 31, 1998

    SciTech Connect (OSTI)

    Green, D.W.; Willhite, G.P.; Walton, A.; McCune, D.; Reynolds, R.; Michnick, M.; Watney, L.

    1998-04-15

    The objective of this project is to address waterflood problems of the type found in Morrow sandstone reservoirs in southwestern Kansas and in Cherokee Group reservoirs in southeastern Kansas. Two demonstration sites operated by different independent oil operators are involved in this project. The Stewart Field is located in Finney County, Kansas and is operated by PetroSantander, Inc. The Nelson Lease is located in Allen County, Kansas, in the N.E. Savonburg Field and is operated by James E. Russell Petroleum, Inc. General topics to be addressed are (1) reservoir management and performance evaluation, (2) waterflood optimization, and (3) the demonstration of recovery processes involving off-the-shelf technologies which can be used to enhance waterflood recovery, increase reserves, and reduce the abandonment rate of these reservoir types. Progress is described for the Stewart field on the following tasks: design/construct waterflood plant; design/construct injection system; design/construct battery consolidation and gathering system; waterflood operations and reservoir management; and technology transfer. Progress for the Savonburg Field includes: water plant development; profile modification treatments; pattern changes and wellbore cleanup; reservoir development (polymer flooding); field operations; and technology transfer.

  20. Improved Oil Recovery in Mississippian Carbonate Reservoirs of Kansas - Near-Term, Class II

    SciTech Connect (OSTI)

    Carr, Timothy R.; Green, Don W.; Willhite, G. Paul

    2001-10-30

    The focus of this project was development and demonstration of cost-effective reservoir description and management technologies to extend the economic life of mature reservoirs in Kansas and the mid-continent.

  1. Visual display of reservoir parameters affecting enhanced oil recovery. Quarterly report, July 1995--September 1995

    SciTech Connect (OSTI)

    Wood, J.R.

    1995-10-01

    Research continued on reservoir characterization. An atlas of thin section petrology of reservoir samples from the Southern San Joaquin Basin was acquired. One-dimensional modeling activities were initiated. Results of a modeling study of Elk Hills is described.

  2. Investigation of oil recovery improvement by coupling an interfacial tension agent and a mobility control agent in light oil reservoirs. Technical progress report, October--December 1994

    SciTech Connect (OSTI)

    Pitts, M.J.

    1994-01-01

    The study will investigate two major areas concerning co-injecting an interfacial tension reduction agent(s) and a mobility control agent into petroleum reservoirs. The first will consist of defining the mechanisms of interaction of an alkaline agent, a surfactant, and a polymer on a fluid-fluid and a fluid-rock basis. The second is the improvement of the economics of the combined technology. This report examines effect of rock type on oil recovery by an alkaline-surfactant-polymer solutions. This report also begins a series of evaluations to improve the economics of alkaline-surfactant-polymer oil recovery.

  3. Silurian "Clinton" Sandstone Reservoir Characterization for Evaluation of CO2-EOR Potential in the East Canton Oil Field, Ohio

    SciTech Connect (OSTI)

    Ronald Riley; John Wicks; Christopher Perry

    2009-12-30

    The purpose of this study was to evaluate the efficacy of using CO2-enhanced oil recovery (EOR) in the East Canton oil field (ECOF). Discovered in 1947, the ECOF in northeastern Ohio has produced approximately 95 million barrels (MMbbl) of oil from the Silurian 'Clinton' sandstone. The original oil-in-place (OOIP) for this field was approximately 1.5 billion bbl and this study estimates by modeling known reservoir parameters, that between 76 and 279 MMbbl of additional oil could be produced through secondary recovery in this field, depending on the fluid and formation response to CO2 injection. A CO2 cyclic test ('Huff-n-Puff') was conducted on a well in Stark County to test the injectivity in a 'Clinton'-producing oil well in the ECOF and estimate the dispersion or potential breakthrough of the CO2 to surrounding wells. Eighty-one tons of CO2 (1.39 MMCF) were injected over a 20-hour period, after which the well was shut in for a 32-day 'soak' period before production was resumed. Results demonstrated injection rates of 1.67 MMCF of gas per day, which was much higher than anticipated and no CO2 was detected in gas samples taken from eight immediately offsetting observation wells. All data collected during this test was analyzed, interpreted, and incorporated into the reservoir characterization study and used to develop the geologic model. The geologic model was used as input into a reservoir simulation performed by Fekete Associates, Inc., to estimate the behavior of reservoir fluids when large quantities of CO2 are injected into the 'Clinton' sandstone. Results strongly suggest that the majority of the injected CO2 entered the matrix porosity of the reservoir pay zones, where it diffused into the oil. Evidence includes: (A) the volume of injected CO2 greatly exceeded the estimated capacity of the hydraulic fracture and natural fractures; (B) there was a gradual injection and pressure rate build-up during the test; (C) there was a subsequent, gradual flashout of the CO2 within the reservoir during the ensuing monitored production period; and (D) a large amount of CO2 continually off-gassed from wellhead oil samples collected as late as 3 1/2 months after injection. After the test well was returned to production, it produced 174 bbl of oil during a 60-day period (September 22 to November 21, 2008), which represents an estimated 58 percent increase in incremental oil production over preinjection estimates of production under normal, conditions. The geologic model was used in a reservoir simulation model for a 700-acre model area and to design a pilot to test the model. The model was designed to achieve a 1-year response time and a five-year simulation period. The reservoir simulation modeling indicated that the injection wells could enhance oil production and lead to an additional 20 percent recovery in the pilot area over a five-year period. The base case estimated that by injecting 500 MCF per day of CO2 into each of the four corner wells, 26,000 STBO would be produced by the central producer over the five-year period. This would compare to 3,000 STBO if a new well were drilled without the benefit of CO2 injection. This study has added significant knowledge to the reservoir characterization of the 'Clinton' in the ECOF and succeeded in identifying a range on CO2-EOR potential. However, additional data on fluid properties (PVT and swelling test), fractures (oriented core and microseis), and reservoir characteristics (relative permeability, capillary pressure, and wet ability) are needed to further narrow the uncertainties and refine the reservoir model and simulation. After collection of this data and refinement of the model and simulation, it is recommended that a larger scale cyclic-CO2 injection test be conducted to better determine the efficacy of CO2-EOR in the 'Clinton' reservoir in the ECOF.

  4. Silurian "Clinton" Sandstone Reservoir Characterization for Evaluation of CO2-EOR Potential in the East Canton Oil Field, Ohio

    SciTech Connect (OSTI)

    Riley, Ronald; Wicks, John; Perry, Christopher

    2009-12-30

    The purpose of this study was to evaluate the efficacy of using CO2-enhanced oil recovery (EOR) in the East Canton oil field (ECOF). Discovered in 1947, the ECOF in northeastern Ohio has produced approximately 95 million barrels (MMbbl) of oil from the Silurian Clinton sandstone. The original oil-in-place (OOIP) for this field was approximately 1.5 billion bbl and this study estimates by modeling known reservoir parameters, that between 76 and 279 MMbbl of additional oil could be produced through secondary recovery in this field, depending on the fluid and formation response to CO2 injection. A CO2 cyclic test (Huff-n-Puff) was conducted on a well in Stark County to test the injectivity in a Clinton-producing oil well in the ECOF and estimate the dispersion or potential breakthrough of the CO2 to surrounding wells. Eighty-one tons of CO2 (1.39 MMCF) were injected over a 20-hour period, after which the well was shut in for a 32-day soak period before production was resumed. Results demonstrated injection rates of 1.67 MMCF of gas per day, which was much higher than anticipated and no CO2 was detected in gas samples taken from eight immediately offsetting observation wells. All data collected during this test was analyzed, interpreted, and incorporated into the reservoir characterization study and used to develop the geologic model. The geologic model was used as input into a reservoir simulation performed by Fekete Associates, Inc., to estimate the behavior of reservoir fluids when large quantities of CO2 are injected into the Clinton sandstone. Results strongly suggest that the majority of the injected CO2 entered the matrix porosity of the reservoir pay zones, where it diffused into the oil. Evidence includes: (A) the volume of injected CO2 greatly exceeded the estimated capacity of the hydraulic fracture and natural fractures; (B) there was a gradual injection and pressure rate build-up during the test; (C) there was a subsequent, gradual flashout of the CO2 within the reservoir during the ensuing monitored production period; and (D) a large amount of CO2 continually off-gassed from wellhead oil samples collected as late as 3 months after injection. After the test well was returned to production, it produced 174 bbl of oil during a 60-day period (September 22 to November 21, 2008), which represents an estimated 58 percent increase in incremental oil production over preinjection estimates of production under normal, conditions. The geologic model was used in a reservoir simulation model for a 700-acre model area and to design a pilot to test the model. The model was designed to achieve a 1-year response time and a five-year simulation period. The reservoir simulation modeling indicated that the injection wells could enhance oil production and lead to an additional 20 percent recovery in the pilot area over a five-year period. The base case estimated that by injecting 500 MCF per day of CO2 into each of the four corner wells, 26,000 STBO would be produced by the central producer over the five-year period. This would compare to 3,000 STBO if a new well were drilled without the benefit of CO2 injection. This study has added significant knowledge to the reservoir characterization of the Clinton in the ECOF and succeeded in identifying a range on CO2-EOR potential. However, additional data on fluid properties (PVT and swelling test), fractures (oriented core and microseis), and reservoir characteristics (relative permeability, capillary pressure, and wet ability) are needed to further narrow the uncertainties and refine the reservoir model and simulation. After collection of this data and refinement of the model and simulation, it is recommended that a larger scale cyclic- CO2 injection test be conducted to better determine the efficacy of CO2-EOR in the Clinton reservoir in the ECOF.

  5. Study of Reservoir Heterogencities and Structural Features Affecting Production in the Shallow Oil Zone, Eastern Elk Hills Area, California

    SciTech Connect (OSTI)

    Janice Gillespie

    2004-11-01

    Late Neogene (Plio-Pleistocene) shallow marine strata of the western Bakersfield Arch and Elk Hills produce hydrocarbons from several different reservoirs. This project focuses on the shallow marine deposits of the Gusher and Calitroleum reservoirs in the Lower Shallow Oil Zone (LSOZ). In the eastern part of the study area on the Bakersfield Arch at North and South Coles Levee field and in two wells in easternmost Elk Hills, the LSOZ reservoirs produce dry (predominantly methane) gas. In structurally higher locations in western Elk Hills, the LSOZ produces oil and associated gas. Gas analyses show that gas from the eastern LSOZ is bacterial and formed in place in the reservoirs, whereas gas associated with oil in the western part of the study area is thermogenic and migrated into the sands from deeper in the basin. Regional mapping shows that the gas-bearing LSOZ sands in the Coles Levee and easternmost Elk Hills area are sourced from the Sierra Nevada to the east whereas the oil-bearing sands in western Elk Hills appear to be sourced from the west. The eastern Elk Hills area occupied the basin depocenter, farthest from either source area. As a result, it collected mainly low-permeability offshore shale deposits. This sand-poor depocenter provides an effective barrier to the updip migration of gases from east to west. The role of small, listric normal faults as migration barriers is more ambiguous. Because our gas analyses show that the gas in the eastern LSOZ reservoirs is bacterial, it likely formed in-place near the reservoirs and did not have to migrate far. Therefore, the gas could have been generated after faulting and accumulated within the fault blocks as localized pools. However, bacterial gas is present in both the eastern AND western parts of Elk Hills in the Dry Gas Zone (DGZ) near the top of the stratigraphic section even though the measured fault displacement is greatest in this zone. Bacterial gas is not present in the west in the deeper LSOZ which has less measured fault displacement. The main difference between the DGZ and the LSOZ appears to be the presence of a sandpoor area in the LSOZ in eastern Elk Hills. The lack of permeable migration pathways in this area would not allow eastern bacterial gas to migrate farther updip into western Elk Hills. A similar sand-poor area does not appear to exist in the DGZ but future research may be necessary to verify this.

  6. Source Term Modeling for Evaluating the Potential Impacts to Groundwater of Fluids Escaping from a Depleted Oil Reservoir Used for Carbon Sequestration

    SciTech Connect (OSTI)

    Cantrell, Kirk J.; Brown, Christopher F.

    2014-06-13

    In recent years depleted oil reservoirs have received special interest as carbon storage reservoirs because of their potential to offset costs through collaboration with enhanced oil recovery projects. Modeling is currently being conducted to evaluate potential risks to groundwater associated with leakage of fluids from depleted oil reservoirs used for storage of CO2. Modeling results reported here focused on understanding how toxic organic compounds found in oil will distribute between the various phases within a storage reservoir after introduction of CO2, understanding the migration potential of these compounds, and assessing potential groundwater impacts should leakage occur. Two model scenarios were conducted to evaluate how organic components in oil will distribute among the phases of interest (oil, CO2, and brine). The first case consisted of 50 wt.% oil and 50 wt.% water; the second case was 90 wt.% CO2 and 10 wt.% oil. Several key organic compounds were selected for special attention in this study based upon their occurrence in oil at significant concentrations, relative toxicity, or because they can serve as surrogate compounds for other more highly toxic compounds for which required input data are not available. The organic contaminants of interest (COI) selected for this study were benzene, toluene, naphthalene, phenanthrene, and anthracene. Partitioning of organic compounds between crude oil and supercritical CO2 was modeled using the Peng-Robinson equation of state over temperature and pressure conditions that represent the entire subsurface system (from those relevant to deep geologic carbon storage environments to near surface conditions). Results indicate that for a typical set of oil reservoir conditions (75°C, and 21,520 kPa) negligible amounts of the COI dissolve into the aqueous phase. When CO2 is introduced into the reservoir such that the final composition of the reservoir is 90 wt.% CO2 and 10 wt.% oil, a significant fraction of the oil dissolves into the vapor phase. As the vapor phase moves up through the stratigraphic column, pressures and temperatures decrease, resulting in significant condensation of oil components. The heaviest organic components condense early in this process (at higher pressures and temperatures), while the lighter components tend to remain in the vapor phase until much lower pressures and temperatures are reached. Based on the model assumptions, the final concentrations of COI to reach an aquifer at 1,520 kPa and 25°C were quite significant for benzene and toluene, whereas the concentrations of polynuclear aromatic hydrocarbons that reach the aquifer were very small. This work demonstrates a methodology that can provide COI source term concentrations in CO2 leaking from a reservoir and entering an overlying aquifer for use in risk assessments.

  7. Post Waterflood CO2 Miscible Flood in Light Oil, Fluvial-Dominated Deltaic Reservoir (Pre-Work and Project Proposal - Appendix)

    SciTech Connect (OSTI)

    Bou-Mikael, Sami

    2002-02-05

    The main objective of the Port Neches Project was to determine the feasibility and producibility of CO2 miscible flooding techniques enhanced with horizontal drilling applied to a Fluvial Dominated Deltaic reservoir. The second was to disseminate the knowledge gained through established Technology Transfer mechanisms to support DOE's programmatic objectives of increasing domestic oil production and reducing abandonment of oil fields.

  8. Advanced Reservoir Characterization in the Antelope Shale to Establish the Viability of CO2 Enhanced Oil Recovery in California's Monterey Formation Siliceous Shales

    SciTech Connect (OSTI)

    Morea, Michael F.

    1999-11-01

    The primary objective of this research is to conduct advanced reservoir characterization and modeling studies in the Antelope Shale reservoir. Characterization studies will be used to determine the technical feasibility of implementing a CO2 enhanced oil recovery project in the Antelope Shale in Buena Vista Hills Field. The Buena Vista Hills pilot CO2 project will demonstrate the economic viability and widespread applicability of CO2 flooding in fractured siliceous shale reservoirs of the San Joaquin Valley. The research consists of four primary work processes: (1) Reservoir Matrix and Fluid Characterization; (2) Fracture characterization; (3) reservoir Modeling and Simulation; and (4) CO2 Pilot Flood and Evaluation. Work done in these areas is subdivided into two phases or budget periods. The first phase of the project will focus on the application of a variety of advanced reservoir characterization techniques to determine the production characteristics of the Antelope Shale reservoir. Reservoir models based on the results of the characterization work will be used to evaluate how the reservoir will respond to secondary recovery and EOR processes. The second phase of the project will include the implementation and evaluation of an advanced enhanced oil recovery (EOR) pilot in the United Anticline (West Dome) of the Buena Vista Hills Field.

  9. Advanced Reservoir Characterization in the Antelope Shale to Establish the Viability of C02 Enhanced Oil Recovery in California's Monterey Formation Siliceous Shales

    SciTech Connect (OSTI)

    Michael F. Morea.

    1998-04-23

    The primary objective of this research is to conduct advanced reservoir characterization and modeling studies in the Antelope Shale reservoir. Characterization studies will be used to determine the technical feasibility of implementing a CO2 enhanced oil recovery project in the Antelope Shale in Buena Vista Hills Field. The Buena Vista Hills pilot CO2 project will demonstrate the economic viability and widespread applicability of CO2 flooding in fractured siliceous shale reservoirs of the San Joaquin Valley. The research consists of four primary work processes: Reservoir Matrix and Fluid Characterization; Fracture Characterization; Reservoir Modeling and Simulation; and CO2 Pilot Flood and Evaluation. Work done in these areas is subdivided into two phases or budget periods. The first phase of the project will focus on the application of a variety of advanced reservoir characterization techniques to determine the production characteristics of the Antelope Shale reservoir. Reservoir models based on the results of the characterization work will be used to evaluate how the reservoir will respond to secondary recovery and EOR processes. The second phase of the project will include the implementation and evaluation of an advanced enhanced oil recovery (EOR) pilot in the United Anticline (West Dome) of the Buena Vista Hills Field.

  10. Advanced Reservoir Characterization in the Antelope Shale to Establish the Viability of CO2 Enhanced Oil Recovery in California's Monterey Formation Siliceous Shales

    SciTech Connect (OSTI)

    Morea, Michael F.

    1999-11-08

    The primary objective of this research is to conduct advanced reservoir characterization and modeling studies in the Antelope Shale reservoir. Characterization studies will be used to determine the technical feasibility of implementing a CO2 enhanced oil recovery project in the Antelope Shale in Buena Vista Hills Field. The Buena Vista Hills pilot CO2 project will demonstrate the economic viability and widespread applicability of CO2 flooding in fractured siliceous shale reservoirs of the San Joaquin Valley. The research consists of four primary work processes: (1) Reservoir Matrix and Fluid Characterization; (2) Fracture characterization; (3) reservoir Modeling and Simulation; and (4) CO2 Pilot Flood and Evaluation. Work done in these areas is subdivided into two phases or budget periods. The first phase of the project will focus on the application of a variety of advanced reservoir characterization techniques to determine the production characteristics of the Antelope Shale reservoir. Reservoir models based on the results of the characterization work will be used to evaluate how the reservoir will respond to secondary recovery and EOR processes. The second phase of the project will include the implementation and evaluation of an advanced enhanced oil recovery (EOR) pilot in the United Anticline (West Dome) of the Buena Vista Hills Field.

  11. Reservoir Characterization of Upper Devonian Gordon Sandstone, Jacksonburg, Stringtown Oil Field, Northwestern West Virginia

    SciTech Connect (OSTI)

    Ameri, S.; Aminian, K.; Avary, K.L.; Bilgesu, H.I.; Hohn, M.E.; McDowell, R.R.; Patchen, D.L.

    2002-05-21

    This report gives results of efforts to determine electrofacies from logs; measure permeability in outcrop to study very fine-scale trends; find the correlation between permeability measured by the minipermeameter and in core plugs, define porosity-permeability flow units; and run the BOAST III reservoir simulator using the flow units defined for the Gordon reservoir.

  12. SMALL, GEOLOGICALLY COMPLEX RESERVOIRS CAN BENEFIT FROM RESERVOIR SIMULATION

    SciTech Connect (OSTI)

    Richard E. Bennett

    2002-06-24

    The Cascade Sand zone of the Mission-Visco Lease in the Cascade Oil field of Los Angeles County, California, has been under water flood since 1970. Increasing water injection to increase oil production rates was being considered as an opportunity to improve oil recovery. However, a secondary gas cap had formed in the up-dip portion of the reservoir with very low gas cap pressures, creating concern that oil could be displaced into the gas cap resulting in the loss of recoverable oil. Therefore, injecting gas into the gas cap to keep the gas cap pressurized and restrict the influx of oil during water injection was also being considered. Further, it was recognized that the reservoir geology in the gas cap area is very complex with numerous folding and faulting and thus there are potential pressure barriers in several locations throughout the reservoir. With these conditions in mind, there were concerns regarding well to well continuity in the gas cap, which could interfere with the intended repressurization impact. Concerns about the pattern of gas flow from well to well, the possibilities of cycling gas without the desired increased pressure, and the possible loss of oil displaced into the gas cap resulted in the decision to conduct a gas tracer survey in an attempt to better define inter-well communication. Following the gas tracer survey, a reservoir model would be developed to integrate the findings of the gas tracer survey, known geologic and reservoir data, and historic production data. The reservoir model would be used to better define the reservoir characteristics and provide information that could help optimize the waterflood-gas injection project under consideration for efficient water and gas injection management to increase oil production. However, due to inadequate gas sampling procedures in the field and insufficiently developed laboratory analytical techniques, the laboratory was unable to detect the tracer in the gas samples taken. At that point, focus on, and an expansion of the scope of the reservoir simulation and modeling effort was initiated, using DOE's BOAST98 (a visual, dynamic, interactive update of BOAST3), 3D, black oil reservoir simulation package as the basis for developing the reservoir model. Reservoir characterization, modeling, and reservoir simulation resulted in a significant change in the depletion strategy. Information from the reservoir characterization and modeling effort indicate that in-fill drilling and relying on natural water influx from the aquifer could increase remaining reserves by 125,000 barrels of oil per well, and that up to 10 infill wells could be drilled in the field. Through this scenario, field production could be increased two to three times over the current 65 bopd. Based on the results of the study, permits have been applied for to drill a directional infill well to encounter the productive zone at a high angle in order to maximize the amount of pay and reservoirs encountered.

  13. Play Analysis and Digital Portfolio of Major Oil Reservoirs in the Permian Basin: Application and Transfer of Advanced Geological and Engineering Technologies for Incremental Production Opportunities

    SciTech Connect (OSTI)

    Shirley P. Dutton; Eugene M. Kim; Ronald F. Broadhead; Caroline L. Breton; William D. Raatz; Stephen C. Ruppel; Charles Kerans

    2004-01-13

    A play portfolio is being constructed for the Permian Basin in west Texas and southeast New Mexico, the largest onshore petroleum-producing basin in the United States. Approximately 1,300 reservoirs in the Permian Basin have been identified as having cumulative production greater than 1 MMbbl (1.59 x 10{sup 5} m{sup 3}) of oil through 2000. Of these significant-sized reservoirs, approximately 1,000 are in Texas and 300 in New Mexico. There are 32 geologic plays that have been defined for Permian Basin oil reservoirs, and each of the 1,300 major reservoirs was assigned to a play. The reservoirs were mapped and compiled in a Geographic Information System (GIS) by play. The final reservoir shapefile for each play contains the geographic location of each reservoir. Associated reservoir information within the linked data tables includes RRC reservoir number and district (Texas only), official field and reservoir name, year reservoir was discovered, depth to top of the reservoir, production in 2000, and cumulative production through 2000. Some tables also list subplays. Play boundaries were drawn for each play; the boundaries include areas where fields in that play occur but are smaller than 1 MMbbl (1.59 x 10{sup 5} m{sup 3}) of cumulative production. Oil production from the reservoirs in the Permian Basin having cumulative production of >1 MMbbl (1.59 x 10{sup 5} m{sup 3}) was 301.4 MMbbl (4.79 x 10{sup 7} m{sup 3}) in 2000. Cumulative Permian Basin production through 2000 was 28.9 Bbbl (4.59 x 10{sup 9} m{sup 3}). The top four plays in cumulative production are the Northwest Shelf San Andres Platform Carbonate play (3.97 Bbbl [6.31 x 10{sup 8} m{sup 3}]), the Leonard Restricted Platform Carbonate play (3.30 Bbbl [5.25 x 10{sup 8} m{sup 3}]), the Pennsylvanian and Lower Permian Horseshoe Atoll Carbonate play (2.70 Bbbl [4.29 x 10{sup 8} m{sup 3}]), and the San Andres Platform Carbonate play (2.15 Bbbl [3.42 x 10{sup 8} m{sup 3}]). Detailed studies of three reservoirs are in progress: Kelly-Snyder (SACROC unit) in the Pennsylvanian and Lower Permian Horseshoe Atoll Carbonate play, Fullerton in the Leonard Restricted Platform Carbonate play, and Barnhart (Ellenburger) in the Ellenburger Selectively Dolomitized Ramp Carbonate play. For each of these detailed reservoir studies, technologies for further, economically viable exploitation are being investigated.

  14. INCREASING HEAVY OIL RESERVES IN THE WILMINGTON OIL FIELD THROUGH ADVANCED RESERVOIR CHARACTERIZATION AND THERMAL PRODUCTION TECHNOLOGIES

    SciTech Connect (OSTI)

    Scott Hara

    2000-12-14

    Through June 2000, project work has been completed on the following activities: data preparation; basic reservoir engineering; developing a deterministic three dimensional (3-D) geologic model, a 3-D deterministic reservoir simulation model and a rock-log model; well drilling and completions; and surface facilities on the Fault Block II-A Tar (Tar II-A) Zone. Work is continuing on improving core analysis techniques, final reservoir tracer work, operational work and research studies to prevent thermal-related formation compaction in the Tar II-A steamflood area, and operational work on the Tar V steamflood pilot and Tar II-A post steamflood project. Work was discontinued on the stochastic geologic model and developing a 3-D stochastic thermal reservoir simulation model of the Tar II-A Zone so the project team could use the 3-D deterministic reservoir simulation model to provide alternatives for the Tar II-A post steamflood operations and shale compaction studies. The project team spent the third quarter 2000 revising the draft 1997-2000 Annual Report submitted last quarter, writing final reports on the research projects mentioned above, and operating the Tar II-A post-steamflood project and the Tar V horizontal well steamflood pilot. Thermal-related formation compaction is a concern of the project team due to observed surface subsidence in the local area above the Tar II-A steamflood project. On January 12, 1999, the steamflood project lost its inexpensive steam source from the Harbor Cogeneration Plant as a result of the recent deregulation of electrical power rates in California. An operational plan was developed and implemented to mitigate the effects of the two situations by injecting cold water into the flanks of the steamflood. The purpose of flank injection has been to increase and subsequently maintain reservoir pressures at a level that would fill-up the steam chests in the ''T'' and ''D'' sands before they can collapse and cause formation compaction and to prevent the steam chests from reoccurring. A new 3-D deterministic thermal reservoir simulation model was used to provide operations with the necessary water injection rates and allowable production rates by well to minimize future surface subsidence and to accurately project reservoir steam chest fill-up by October 1999. A geomechanics study and a separate reservoir simulation study have been performed to determine the possible indicators of formation compaction, the temperatures at which specific indicators are affected and the projected temperature profiles in the over and underburden shales over a ten year period following steam injection. Further geomechanics work should be conducted. It was believed that once steam chest fill-up occurred, the reservoir would act more like a waterflood and production and cold water injection could be operated at lower Injection to production ratios (I/P) and net injection rates. In mid-September 1999, net water injection was reduced substantially in the ''D'' sands following steam chest fill-up. This caused reservoir pressures to plummet about 100 psi within six weeks. Starting in late-October 1999, net ''D'' sand injection was increased and reservoir pressures increased back to steam chest fill-up pressures of 90% hydrostatic pressure by March 2000 and have been maintained through September 2000. When the ''T'' sands reached fill-up in October 1999, net ''T'' sand injection remained at a high rate through April 2000 and reservoir pressures stabilized at 98% hydrostatic pressure. The objective is to lower ''T'' sand pressure slowly to 90% hydrostatic. Net injection was reduced and ''T'' sand reservoir pressure was at 97% hydrostatic in September 2000. A more detailed discussion of the operational changes is in the Reservoir Management section of this report. A reservoir pressure monitoring program was developed as part of the poststeamflood reservoir management plan. This bi-monthly sonic fluid level program measures the static fluid levels in all idle wells an average of once a month.

  15. INCREASING HEAVY OIL RESERVES IN THE WILMINGTON OIL FIELD THROUGH ADVANCED RESERVOIR CHARACTERIZATION AND THERMAL PRODUCTION TECHNOLOGIES

    SciTech Connect (OSTI)

    Scott Hara

    2000-12-06

    Through March 2000, project work has been completed on the following activities: data preparation; basic reservoir engineering; developing a deterministic three dimensional (3-D) geologic model, a 3-D deterministic reservoir simulation model and a rock-log model; well drilling and completions; and surface facilities on the Fault Block II-A Tar (Tar II-A) Zone. Work is continuing on improving core analysis techniques, final reservoir tracer work, operational work and research studies to prevent thermal-related formation compaction in the Tar II-A steamflood area, and operational work on the Tar V steamflood pilot and Tar II-A post steamflood project. Work was discontinued on the stochastic geologic model and developing a 3-D stochastic thermal reservoir simulation model of the Tar II-A Zone so the project team could use the 3-D deterministic reservoir simulation model to provide alternatives for the Tar II-A post steamflood operations and shale compaction studies. The project team spent the second quarter 2000 writing the 1997-2000 Annual Report, completing research for the project on the subjects mentioned above, and operating the Tar II-A post-steamflood project and the Tar V horizontal well steamflood pilot. Thermal-related formation compaction is a concern of the project team due to observed surface subsidence in the local area above the Tar II-A steamflood project. On January 12, 1999, the steamflood project lost its inexpensive steam source from the Harbor Cogeneration Plant as a result of the recent deregulation of electrical power rates in California. An operational plan was developed and implemented to mitigate the effects of the two situations by injecting cold water into the flanks of the steamflood. The purpose of flank injection has been to increase and subsequently maintain reservoir pressures at a level that would fill-up the steam chests in the ''T'' and ''D'' sands before they can collapse and cause formation compaction and to prevent the steam chests from reoccurring. A new 3-D deterministic thermal reservoir simulation model was used to provide operations with the necessary water injection rates and allowable production rates by well to minimize future surface subsidence and to accurately project reservoir steam chest fill-up by October 1999. A geomechanics study and a separate reservoir simulation study have been performed to determine the possible indicators of formation compaction, the temperatures at which specific indicators are affected and the projected temperature profiles in the over and underburden shales over a ten year period following steam injection. Further geomechanics work should be conducted. It was believed that once steam chest fill-up occurred, the reservoir would act more like a waterflood and production and cold water injection could be operated at lower Injection to production ratios (I/P) and net injection rates. In mid-September 1999, net water injection was reduced substantially in the ''D'' sands following steam chest fill-up. This caused reservoir pressures to plummet about 100 psi within six weeks. Starting in late-October 1999, net ''D'' sand injection was increased and reservoir pressures have slowly increased back to steam chest fill-up pressures as of the end of March 2000. When the ''T'' sands reached fill-up, net ''T'' sand injection remained at a high rate and reservoir pressures stabilized. A more detailed discussion of the operational changes is in the Reservoir Management section of this report. A reservoir pressure monitoring program was developed as part of the poststeamflood reservoir management plan. This bi-monthly sonic fluid level program measures the static fluid levels in all idle wells an average of once a month. The fluid levels have been calibrated for liquid and gas density gradients by comparing a number of them with Amerada bomb pressures taken within a few days. This data allows engineering to respond quickly to rises or declines in reservoir pressure by either increasing injection or production or idling production. Expanding thermal recovery oper

  16. Increased Oil Production and Reserves Utilizing Secondary/Tertiary Recovery Techniques on Small Reservoirs in the Paradox Basin, Utah

    SciTech Connect (OSTI)

    Chidsey Jr., Thomas C.

    2003-02-06

    The primary objective of this project was to enhance domestic petroleum production by field demonstration and technology transfer of an advanced-oil-recovery technology in the Paradox Basin, southeastern Utah. If this project can demonstrate technical and economic feasibility, the technique can be applied to approximately 100 additional small fields in the Paradox Basin alone, and result in increased recovery of 150 to 200 million barrels (23,850,000-31,800,000 m3) of oil. This project was designed to characterize five shallow-shelf carbonate reservoirs in the Pennsylvanian (Desmoinesian) Paradox Formation and choose the best candidate for a pilot demonstration project for either a waterflood or carbon-dioxide-(CO2-) miscible flood project. The field demonstration, monitoring of field performance, and associated validation activities will take place within the Navajo Nation, San Juan County, Utah.

  17. Increased Oil Production and Reserves Utilizing Secondary/Tertiary Recovery Techniques on Small Reservoirs in the Paradox Basin, Utah

    SciTech Connect (OSTI)

    Jr., Chidsey, Thomas C.; Allison, M. Lee

    1999-11-02

    The primary objective of this project is to enhance domestic petroleum production by field demonstration and technology transfer of an advanced- oil-recovery technology in the Paradox basin, southeastern Utah. If this project can demonstrate technical and economic feasibility, the technique can be applied to approximately 100 additional small fields in the Paradox basin alone, and result in increased recovery of 150 to 200 million barrels (23,850,000-31,800,000 m3) of oil. This project is designed to characterize five shallow-shelf carbonate reservoirs in the Pennsylvanian (Desmoinesian) Paradox Formation and choose the best candidate for a pilot demonstration project for either a waterflood or carbon-dioxide-(CO2-) miscible flood project. The field demonstration, monitoring of field performance, and associated validation activities will take place within the Navajo Nation, San Juan County, Utah.

  18. Increased oil production and reserves utilizing secondary/tertiary recovery techniques on small reservoirs in the Paradox basin, Utah. Annual report, February 9, 1996--February 8, 1997

    SciTech Connect (OSTI)

    Chidsey, T.C. Jr.

    1997-08-01

    The Paradox basin of Utah, Colorado, and Arizona contains nearly 100 small oil fields producing from carbonate buildups or mounds within the Pennsylvanian (Desmoinesian) Paradox Formation. These fields typically have one to four wells with primary production ranging from 700,000 to 2,000,000 barrels of oil per field at a 15 to 20% recovery rate. At least 200 million barrels of oil is at risk of being unrecovered in these small fields because of inefficient recovery practices and undrained heterogeneous reservoirs. Five fields (Anasazi, Mule, Blue Hogan, Heron North, and Runway) within the Navajo Nation of southeastern Utah are being evaluated for waterflood or carbon-dioxide-miscible flood projects based upon geological characterization and reservoir modeling. The results can be applied to other fields in the Paradox basin and the Rocky Mountain region, the Michigan and Illinois basins, and the Midcontinent. The Anasazi field was selected for the initial geostatistical modeling and reservoir simulation. A compositional simulation approach is being used to model primary depletion, waterflood, and CO{sub 2}-flood processes. During this second year of the project, team members performed the following reservoir-engineering analysis of Anasazi field: (1) relative permeability measurements of the supra-mound and mound-core intervals, (2) completion of geologic model development of the Anasazi reservoir units for use in reservoir simulation studies including completion of a series of one-dimensional, carbon dioxide-displacement simulations to analyze the carbon dioxide-displacement mechanism that could operate in the Paradox basin system of reservoirs, and (3) completion of the first phase of the full-field, three-dimensional Anasazi reservoir simulation model, and the start of the history matching and reservoir performance prediction phase of the simulation study.

  19. WETTABILITY AND PREDICTION OF OIL RECOVERY FROM RESERVOIRS DEVELOPED WITH MODERN DRILLING AND COMPLETION FLUIDS

    SciTech Connect (OSTI)

    Jill S. Buckley; Norman R. Morrow

    2004-11-01

    Contamination of crude oils by surface-active agents from drilling fluids or other oil-field chemicals is more difficult to detect and quantify than bulk contamination with, for example, base fluids from oil-based muds. Bulk contamination can be detected by gas chromatography or other common analytical techniques, but surface-active contaminants can be influential at much lower concentrations that are more difficult to detect analytically, especially in the context of a mixture as complex as a crude oil. In this report we present a baseline study of interfacial tensions of 39 well-characterized crude oil samples with aqueous phases that vary in pH and ionic composition. This extensive study will provide the basis for assessing the effects of surface-active contaminant on interfacial tension and other surface properties of crude oil/brine/rock ensembles.

  20. PLAY ANALYSIS AND DIGITAL PORTFOLIO OF MAJOR OIL RESERVOIRS IN THE PERMIAN BASIN: APPLICATION AND TRANSFER OF ADVANCED GEOLOGICAL AND ENGINEERING TECHNOLOGIES FOR INCREMENTAL PRODUCTION OPPORTUNITIES

    SciTech Connect (OSTI)

    Shirley P. Dutton; Eugene M. Kim; Ronald F. Broadhead; William Raatz; Cari Breton; Stephen C. Ruppel; Charles Kerans; Mark H. Holtz

    2003-04-01

    A play portfolio is being constructed for the Permian Basin in west Texas and southeast New Mexico, the largest petroleum-producing basin in the US. Approximately 1300 reservoirs in the Permian Basin have been identified as having cumulative production greater than 1 MMbbl of oil through 2000. Of these major reservoirs, approximately 1,000 are in Texas and 300 in New Mexico. On a preliminary basis, 32 geologic plays have been defined for Permian Basin oil reservoirs and assignment of each of the 1300 major reservoirs to a play has begun. The reservoirs are being mapped and compiled in a Geographic Information System (GIS) by play. Detailed studies of three reservoirs are in progress: Kelly-Snyder (SACROC unit) in the Pennsylvanian and Lower Permian Horseshoe Atoll Carbonate play, Fullerton in the Leonardian Restricted Platform Carbonate play, and Barnhart (Ellenburger) in the Ellenburger Selectively Dolomitized Ramp Carbonate play. For each of these detailed reservoir studies, technologies for further, economically viable exploitation are being investigated.

  1. Improved oil recovery in fluvial dominated deltaic reservoirs of Kansas - Near-term. Annual report, June 18, 1993--June 18, 1994

    SciTech Connect (OSTI)

    Green, D.W.; Willhite, G.P.

    1995-10-01

    Common oil field problems exist in fluvial dominated deltaic reservoirs in Kansas. The problems are poor waterflood sweep and lack of reservoir management. The poor waterflood sweep efficiency is due to (1) reservoir heterogeneity, (2) channeling of injected water through high permeability zones or fractures, and (3) clogging of water injection wells with solids as a result of poor water quality. In many instances the lack of reservoir management is due to lack of (1) data collection and organization, (2) integrated analysis of existing data by geological and engineering personnel, and (3) identification of optimum recovery techniques. Two demonstration sites operated by different independent oil operators are involved in the project. The Nelson Lease (an existing waterflood) is located in Allen County, Kansas in the N.E. Savonburg Field and is operated by James E. Russell Petroleum, Inc. The Stewart Field (on the latter stage of primary production) is located in Finney County, Kansas and is operated by Sharon Resources, Inc. The objective is to increase recovery efficiency and economics in these type of reservoirs. The technologies being applied to increase waterflood sweep efficiency are (1) in situ permeability modification treatments, (2) infill drilling, (3) pattern changes, and (4) air flotation to improve water quality. The technologies being applied to improve reservoir management are (1) database development, (2) reservoir simulation, (3) transient testing, (4) database management, and (5) integrated geological and engineering analysis.

  2. Improved oil recovery in fluvial dominated deltaic reservoirs of Kansas - near - term. Technical progress report, June 17, 1994--June 17, 1995

    SciTech Connect (OSTI)

    1996-07-01

    Common oil field problems exist in fluvial dominated deltaic reservoirs in Kansas. The problems are poor waterflood sweep and lack of reservoir management. The poor waterflood sweep efficiency is due to (1) reservoir heterogeneity, (2) channeling of injected water through high permeability zones or fractures, and (3) clogging of water injection wells with solids as a result of poor water quality. In many instances the lack of reservoir management is due to lack of (1) data collection and organization, (2) integrated analysis of existing data by geological and engineering personnel, and (3) identification of optimum recovery techniques. Two demonstration sites operated by different independent oil operators are involved in the project. The Stewart Field (on the latter stage of primary production) is located in Finney County, Kansas, and was operated by Sharon Resources, Inc. and is now operated by North American Resources Company. The Nelson Lease (an existing waterflood) is located in Allen County, Kansas, in the N.E. Savonburg Field and is operated by James E. Russell Petroleum, Inc. The objective is to increase recovery efficiency and economics in these type of reservoirs. The technologies being applied to increase waterflood sweep efficiency are (1) in situ permeability modification treatments, (2) infill drilling, (3) pattern changes, and (4) air flotation to improve water quality. The technologies being applied to improve reservoir management are (1) database development, (2) reservoir simulation, (3) transient testing, (4) database management, and (5) integrated geological and engineering analysis.

  3. PLAY ANALYSIS AND DIGITAL PORTFOLIO OF MAJOR OIL RESERVOIRS IN THE PERMIAN BASIN: APPLICATION AND TRANSFER OF ADVANCED GEOLOGICAL AND ENGINEERING TECHNOLOGIES FOR INCREMENTAL PRODUCTION OPPORTUNITIES

    SciTech Connect (OSTI)

    Shirley P. Dutton; Eugene M. Kim; Ronald F. Broadhead; Caroline L. Breton; William D. Raatz; Stephen C. Ruppel; Charles Kerans

    2004-05-01

    The Permian Basin of west Texas and southeast New Mexico has produced >30 Bbbl (4.77 x 10{sup 9} m{sup 3}) of oil through 2000, most of it from 1,339 reservoirs having individual cumulative production >1 MMbbl (1.59 x 10{sup 5} m{sup 3}). These significant-sized reservoirs are the focus of this report. Thirty-two Permian Basin oil plays were defined, and each of the 1,339 significant-sized reservoirs was assigned to a play. The reservoirs were mapped and compiled in a Geographic Information System (GIS) by play. Associated reservoir information within linked data tables includes Railroad Commission of Texas reservoir number and district (Texas only), official field and reservoir name, year reservoir was discovered, depth to top of the reservoir, production in 2000, and cumulative production through 2000. Some tables also list subplays. Play boundaries were drawn for each play; the boundaries include areas where fields in that play occur but are <1 MMbbl (1.59 x 10{sup 5} m{sup 3}) of cumulative production. This report contains a summary description of each play, including key reservoir characteristics and successful reservoir-management practices that have been used in the play. The CD accompanying the report contains a pdf version of the report, the GIS project, pdf maps of all plays, and digital data files. Oil production from the reservoirs in the Permian Basin having cumulative production >1 MMbbl (1.59 x 10{sup 5} m{sup 3}) was 301.4 MMbbl (4.79 x 10{sup 7} m{sup 3}) in 2000. Cumulative Permian Basin production through 2000 from these significant-sized reservoirs was 28.9 Bbbl (4.59 x 10{sup 9} m{sup 3}). The top four plays in cumulative production are the Northwest Shelf San Andres Platform Carbonate play (3.97 Bbbl [6.31 x 10{sup 8} m{sup 3}]), the Leonard Restricted Platform Carbonate play (3.30 Bbbl 5.25 x 10{sup 8} m{sup 3}), the Pennsylvanian and Lower Permian Horseshoe Atoll Carbonate play (2.70 Bbbl [4.29 x 10{sup 8} m{sup 3}]), and the San Andres Platform Carbonate play (2.15 Bbbl [3.42 x 10{sup 8} m{sup 3}]).

  4. Visual display of reservoir parameters affecting enhanced oil recovery. Final report, September 29, 1993--September 28, 1996

    SciTech Connect (OSTI)

    Wood, J.R.

    1997-05-01

    The Pioneer Anticline, 25 miles southwest of Bakersfield, California, which has yielded oil since 1926, was the subject of a three-year study aimed at recovering more oil. A team from Michigan Technological University of Houghton, Michigan (MTU), and Digital Petrophysics, Inc. of Bakersfield, California (DPI), undertook the study as part of the Department of Energy`s Advanced Extraction and Process Technology Program. The program provides support for projects which cross-cut geoscience and engineering research in order to develop innovative technologies for increasing the recovery of some of the estimated 340 billion barrels of in-place oil remaining in U.S. reservoirs. In recent years, low prices and declining production have increased the likelihood that oil fields will be prematurely abandoned, locking away large volumes of unrecovered oil. The major companies have sold many of their fields to smaller operators in an attempt to concentrate their efforts on fewer {open_quotes}core{close_quotes} properties and on overseas exploration. As a result, small companies with fewer resources at their disposal are becoming responsible for an ever-increasing share of U.S. production. The goal of the MTU-DPI project was to make small independent producers who are inheriting old fields from the majors aware that high technology computer software is now available at relatively low cost. In this project, a suite of relatively inexpensive, PC-based software packages, including a commercial database, a multimedia presentation manager, several well-log analysis program, a mapping and cross-section program, and 2-D and 3-D visualization programs, were tested and evaluated on Pioneer Anticline in the southern San Joaquin Valley of California. These relatively inexpensive, commercially available PC-based programs can be assembled into a compatible package for a fraction of the cost of a workstation program with similar capabilities.

  5. WETTABILITY AND PREDICTION OF OIL RECOVERY FROM RESERVOIRS DEVELOPED WITH MODERN DRILLING AND COMPLETION FLUIDS

    SciTech Connect (OSTI)

    Jill S. Buckley; Norman R. Morrow

    2004-05-01

    We report on progress in three areas. In part one, the wetting effects of synthetic base oils are reported. Part two reports progress in understanding the effects of surfactants of known chemical structures, and part three integrates the results from surface and core tests that show the wetting effects of commercial surfactant products used in synthetic and traditional oil-based drilling fluids. An important difference between synthetic and traditional oil-based muds (SBM and OBM, respectively) is the elimination of aromatics from the base oil to meet environmental regulations. The base oils used include dearomatized mineral oils, linear alpha-olefins, internal olefins, and esters. We show in part one that all of these materials except the esters can, at sufficiently high concentrations, destabilize asphaltenes. The effects of asphaltenes on wetting are in part related to their stability. Although asphaltenes have some tendency to adsorb on solid surfaces from a good solvent, that tendency can be much increased near the onset of asphaltene instability. Tests in Berea sandstone cores demonstrate wetting alteration toward less water-wet conditions that occurs when a crude oil is displaced by paraffinic and olefinic SBM base oils, whereas exposure to the ester products has little effect on wetting properties of the cores. Microscopic observations with atomic forces microscopy (AFM) and macroscopic contact angle measurements have been used in part 2 to explore the effects on wetting of mica surfaces using oil-soluble polyethoxylated amine surfactants with varying hydrocarbon chain lengths and extent of ethoxylation. In the absence of water, only weak adsorption occurs. Much stronger, pH-dependent adsorption was observed when water was present. Varying hydrocarbon chain length had little or no effect on adsorption, whereas varying extent of ethoxylation had a much more significant impact, reducing contact angles at nearly all conditions tested. Preequilibration of aqueous and oleic phases appeared to have little influence over surfactant interactions with the mica surface; the solubility in water of all three structures appeared to be very limited. Commercial emulsifiers for both SBM and OBM formulations are blends of tall oil fatty acids and their polyaminated derivatives. In part three of this report, we integrate observations on smooth surfaces with those in Berea sandstone cores to show the effects of low concentrations of these products with and without the added complexity of adsorbed material from crude oils. Unlike the polyethoxylated amines studied in part two, there are significant non-equilibrium effects that can occur when water first contacts oil with dissolved surfactant. Very oil-wet conditions can be produced on first contact. Surfactant dissolved in oil had less effect on wetting alteration for one combination of crude oil and surfactant, although the generality of this observation can only be assessed by additional tests with crude oils of different composition. The wettability-altering effect of surfactants on both mica and Berea sandstone was most significant when they contacted surfaces after adsorption of crude oil components. Tests without crude oil might underestimate the extent of wetting change possible with these SBM and OBM emulsifiers.

  6. Increased oil production and reserves utilizing secondary/tertiary recovery techniques on small reservoirs in the Paradox basin, Utah. Annual report

    SciTech Connect (OSTI)

    Chidsey, T.C. Jr.

    1997-02-01

    The Paradox basin of Utah, Colorado, and Arizona contains nearly 100 small oil fields producing from carbonate buildups or mounds within the Pennsylvanian (Desmoinesian) Paradox Formation. These fields typically have one to four wells with primary production ranging from 700,000 to 2,000,000 barrels of oil per field at a 15 to 20% recovery rate. At least 200 million barrels of oil is at risk of being unrecovered in these small fields because of inefficient recovery practices and undrained heterogeneous reservoirs. Five fields (Anasazi, mule, Blue Hogan, heron North, and Runway) within the Navajo Nation of southeastern utah are being evaluated for waterflood or carbon-dioxide-miscible flood projects based upon geological characterization and reservoir modeling. The results can be applied to other fields in the Paradox basin and the Rocky Mountain region, the Michigan and Illinois basins, and the Midcontinent. The reservoir engineering component of the work completed to date included analysis of production data and well tests, comprehensive laboratory programs, and preliminary mechanistic reservoir simulation studies. A comprehensive fluid property characterization program was completed. Mechanistic reservoir production performance simulation studies were also completed.

  7. Method for providing solids-free production from heavy oil reservoirs

    SciTech Connect (OSTI)

    Jennings, A.R.; Smith, R.C.

    1991-08-06

    This patent describes a method for producing viscous substantially solids free hydrocarbonaceous fluids from an unconsolidated formation or reservoir. It includes drilling into the reservoir first and second spaced apart wells into a lower productive interval of the formation; perforating both wells in the lower productive interval; fracturing hydraulically the wells at the lower productive interval with a viscous fracturing fluid containing a proppant therein so as to prop a created fracture; injecting a pre-determined volume of steam into the first well in an amount sufficient to soften the viscous fluid and lower the viscosity of the fluid adjacent a fractured face; producing the first well at a rate sufficient to allow formation fines to build up on a fracture face communicating with the first well thereby resulting in a filter screen sufficient to substantially remove formation fines from the hydrocarbonaceous fluids.

  8. Post Waterflood CO{sub 2} Miscible Flood in Light Oil Fluvial-Dominated Deltaic Reservoirs

    SciTech Connect (OSTI)

    1996-04-30

    Texaco terminated the CO{sub 2} purchase agreement with Cardox due to the declining production from the project during 1995. This decision was supported by the DOE and the Exploration and Production Technology Department (EPTD) who developed the model to simulate reservoir performance. Texaco is planning to continue recycling produced CO{sub 2} to recover the remaining 400 MBO from the Marg Area 1 reservoir. Currently one well is remaining on production Kuhn {number_sign}15R after the second producing well Kuhn {number_sign}38 sanded up. Changing the water and CO{sub 2} injection patterns should improve the sweep efficiency and restore production from other existing wells.

  9. Post Waterflood C02 Miscible Flood in Light Oil Fluvial-Dominated Deltaic Reservoirs

    SciTech Connect (OSTI)

    John Augustine

    1998-01-13

    Only one well remains in production in the Port Neches CO2 project; Kuhn #14. Production from this project is approaching economic limit and the project is nearing termination at this point. The work over to return Kuhn #38 to production failed and the well is currently shut in. All produced CO2 is currently being reinjected in the reservoir. The CO2 recycled volume is 2 MMCFD.

  10. Post Waterflood CO2 Miscible Flood in Light Oil, Fluvial-Dominated Deltaic Reservoir (Pre-Work and Project Proposal), Class I

    SciTech Connect (OSTI)

    Bou-Mikael, Sami

    2002-02-05

    This project outlines a proposal to improve the recovery of light oil from waterflooded fluvial dominated deltaic (FDD) reservoir through a miscible carbon dioxide (CO2) flood. The site is the Port Neches Field in Orange County, Texas. The field is well explored and well exploited. The project area is 270 acres within the Port Neches Field.

  11. Pompano subsea development -- TFL well design for deepwater unconsolidated waxy oil reservoirs

    SciTech Connect (OSTI)

    Holt, J.; Black, J.W.; Meader, A.; Whitehead, N.

    1996-12-31

    BP Exploration`s Pompano subsea development, in 1,865 ft of water uses a subsea production system to produce oil to a host platform 4.5 miles away. This paper describes the well construction and completion design for a template/manifold Through Flowline (TFL) subsea oil production system. Included are an outline of the rig upgrade requirements, casing design, completion design, and simultaneous operations strategy. It will provide a useful guide for drilling staff involved in planning and execution of a subsea development.

  12. An integrated approach to seismic stimulation of oil reservoirs: laboratory, field and theoretical results from DOE/industry collaborations.

    SciTech Connect (OSTI)

    Roberts, P. M.; Majer, Ernest Luther; Lo, W. C.; Sposito, Garrison,; Daley, T. M.

    2003-01-01

    It has been observed repeatedly that low-frequency (10-500 Hz) seismic stress waves can enhance oil production from depleted reservoirs . Until recently, the majority of these observations have been anecdotal or at the proof-of-concept level. The physics coupling stress waves to multiphase fluid flow behavior in porous media is still poorly understood, even though numerous underlying physical mechanisms have been proposed to explain the observations . Basic research on the phenomenon is being conducted through a U .S. Department of Energy funded collaboration between Lawrence Berkeley National Laboratory, the University of California at Berkeley, Los Alamos National Laboratory and the U .S . oil and gas industry . The project has focused on three main areas of research: (1) laboratory core flow experiments, (2) field seismic monitoring of downhole stimulation tests, and (3) theoretical modeling of the coupled stress/flow phenomenon . The major goal is to obtain a comprehensive scientific understanding of the seismic stimulation phenomenon so that field application technologies can be improved. Initial developments and experimental results in all three research focus areas confirm historic observations that the stimulated flow phenomenon is real and that a fundamental scientific understanding can be obtained through continued research . Examples of project results and developments are presented here.

  13. Increased Oil Production and Reserves Utilizing Secondary/Tertiary Recovery Techniques on Small Reservoirs in the Paradox Basin, Utah

    SciTech Connect (OSTI)

    Allison, M. Lee; Chidsey, Jr., Thomas

    1999-11-03

    The primary objective of this project is to enhance domestic petroleum production by demonstration and technology transfer of an advanced oil recovery technology in the Paradox basin, southeastern Utah. If this project can demonstrate technical and economic feasibility, the technique can be applied to about 100 additional small fields in the Paradox basin alone, and result in increased recovery of 150 to 200 million bbl of oil. This project is designed to characterize five shallow-shelf carbonate reservoirs in the Pennsylvanian (Desmoinesian) Paradox Formation and choose the best candidate for a pilot demonstration project for either a waterflood or carbon dioxide-(CO-) flood 2 project. The field demonstration, monitoring of field performance, and associated validation activities will take place in the Paradox basin within the Navajo Nation. The results of this project will be transferred to industry and other researchers through a petroleum extension service, creation of digital databases for distribution, technical workshops and seminars, field trips, technical presentations at national and regional professional meetings, and publication in newsletters and various technical or trade journals.

  14. Increased Oil Production and Reserves Utilizing Secondary/Tertiary Recovery Techniques on Small Reservoirs in the Paradox Basin, Utah.

    SciTech Connect (OSTI)

    Chidsey, T.C. Jr.; Lorenz, D.M.; Culham, W.E.

    1997-10-15

    The primary objective of this project is to enhance domestic petroleum production by demonstration and technology transfer of an advanced oil recovery technology in the Paradox basin, southeastern Utah. If this project can demonstrate technical and economic feasibility, the technique can be applied to approximately 100 additional small fields in the Paradox basin alone, and result in increased recovery of 150 to 200 million barrels of oil. This project is designed to characterize five shallow-shelf carbonate reservoirs in the Pennsylvanian (Desmoinesian) Paradox Formation and choose the best candidate for a pilot demonstration project for either a waterflood or carbon dioxide- (CO{sub 2}-) flood project. The field demonstration, monitoring of field performance, and associated validation activities will take place in the Paradox basin within the Navajo Nation. The results of this project will be transferred to industry and other researchers through a petroleum extension service, creation of digital databases for distribution, technical workshops and seminars, field trips, technical presentations at national and regional professional meetings, and publication in newsletters and various technical or trade journals.

  15. Method for improving sustained solids-free production from heavy oil reservoirs

    SciTech Connect (OSTI)

    Jennings, A.R.; Smith, R.C.

    1991-08-06

    This patent describes a method for producing viscous substantially solids-free hydrocarbonaceous fluids from an unconsolidated formation or reservoir. It includes drilling into the reservoir first and second spaced apart wells into a lower productive interval of the formation; perforating both wells in the lower productive interval; fracturing hydraulically the wells at the productive interval with a viscous fracturing fluid containing a propant therein so as to prop a created fracture and form a fines screen; injecting a pre-determined volume of steam into the first well in an amount sufficient to soften the viscous fluid and lower the viscosity of the fluid adjacent a fracture face; producing the first well at a rate sufficient to allow formation fines to build up on a fracture face communicating with the first well thereby resulting in a filter screen sufficient to substantially remove formation fines from the hydrocarbonaceous fluids; shutting in the first well while injecting steam in a predetermined amount in the second well; shutting in the second well.

  16. Method for identifying subsurface fluid migration and drainage pathways in and among oil and gas reservoirs using 3-D and 4-D seismic imaging

    DOE Patents [OSTI]

    Anderson, Roger N.; Boulanger, Albert; Bagdonas, Edward P.; Xu, Liqing; He, Wei

    1996-01-01

    The invention utilizes 3-D and 4-D seismic surveys as a means of deriving information useful in petroleum exploration and reservoir management. The methods use both single seismic surveys (3-D) and multiple seismic surveys separated in time (4-D) of a region of interest to determine large scale migration pathways within sedimentary basins, and fine scale drainage structure and oil-water-gas regions within individual petroleum producing reservoirs. Such structure is identified using pattern recognition tools which define the regions of interest. The 4-D seismic data sets may be used for data completion for large scale structure where time intervals between surveys do not allow for dynamic evolution. The 4-D seismic data sets also may be used to find variations over time of small scale structure within individual reservoirs which may be used to identify petroleum drainage pathways, oil-water-gas regions and, hence, attractive drilling targets. After spatial orientation, and amplitude and frequency matching of the multiple seismic data sets, High Amplitude Event (HAE) regions consistent with the presence of petroleum are identified using seismic attribute analysis. High Amplitude Regions are grown and interconnected to establish plumbing networks on the large scale and reservoir structure on the small scale. Small scale variations over time between seismic surveys within individual reservoirs are identified and used to identify drainage patterns and bypassed petroleum to be recovered. The location of such drainage patterns and bypassed petroleum may be used to site wells.

  17. Method for identifying subsurface fluid migration and drainage pathways in and among oil and gas reservoirs using 3-D and 4-D seismic imaging

    DOE Patents [OSTI]

    Anderson, R.N.; Boulanger, A.; Bagdonas, E.P.; Xu, L.; He, W.

    1996-12-17

    The invention utilizes 3-D and 4-D seismic surveys as a means of deriving information useful in petroleum exploration and reservoir management. The methods use both single seismic surveys (3-D) and multiple seismic surveys separated in time (4-D) of a region of interest to determine large scale migration pathways within sedimentary basins, and fine scale drainage structure and oil-water-gas regions within individual petroleum producing reservoirs. Such structure is identified using pattern recognition tools which define the regions of interest. The 4-D seismic data sets may be used for data completion for large scale structure where time intervals between surveys do not allow for dynamic evolution. The 4-D seismic data sets also may be used to find variations over time of small scale structure within individual reservoirs which may be used to identify petroleum drainage pathways, oil-water-gas regions and, hence, attractive drilling targets. After spatial orientation, and amplitude and frequency matching of the multiple seismic data sets, High Amplitude Event (HAE) regions consistent with the presence of petroleum are identified using seismic attribute analysis. High Amplitude Regions are grown and interconnected to establish plumbing networks on the large scale and reservoir structure on the small scale. Small scale variations over time between seismic surveys within individual reservoirs are identified and used to identify drainage patterns and bypassed petroleum to be recovered. The location of such drainage patterns and bypassed petroleum may be used to site wells. 22 figs.

  18. Post waterflood CO{sub 2} miscible flood in light oil fluvial - dominated deltaic reservoirs. Fourth quarterly progress report, July 1, 1995--September 30, 1995

    SciTech Connect (OSTI)

    1995-11-10

    Production from the Marg Area 1 at Port Neches is averaging 222 BOPD for this quarter. The production drop is due in part to mechanical problems and to poor sweep efficiency caused by water blockage that prevented the CO{sub 2} from contacting new residual oil deeper in the reservoir. Alternating water and gas injection assisted to some extent in maintaining oil production and improved the reservoir yield by reducing the gas production. A workover was performed on well Kuhn No. 38 to correct failed gravel pack setting. Production from the well was restored to 60 BOPD. Plugging of the injection wells continue to be a problem, reducing the injection rate in critical areas of the reservoir, near well Kuhn No. 15R. Texaco drilled the well Polk B No. 39 to The Marg Area 3 reservoir to gain structural position based on the 3D seismic, and found the sand present as anticipated. However, the sand did not have any hydrocarbon accumulation. For this reason, Texaco will abandon testing the idea of utilizing CO{sub 2} to accelerate the primary production rate and reduce water production and primary production cycle time, in the reservoir.

  19. Improved oil recovery in fluvial dominated deltaic reservoirs of Kansas -- near-term. Seventh quarterly report, February 1, 1995--April 1, 1995

    SciTech Connect (OSTI)

    Green, D.W.; Willhite, G.P.; Walton, A.; Schoeling, L.; Reynolds, R.; Michnick, M.; Watney, L.

    1995-04-15

    The objective of this project is to address waterflood problems of the type found in Cherokee Group reservoirs in southeastern Kansas and in Morrow sandstone reservoirs in southwestern Kansas. Two demonstration sites operated by different independent oil operators are involved in the project. The Nelson Lease (an existing waterflood) is located in Allen County, Kansas in the N.E. Savonburg Field and is operated by James E. Russell Petroleum, Inc. The Stewart Field (on latter stage of primary production) is located in Finney County, Kansas and is operated by Sharon Resources, Inc. General topics to be addressed will be (1) reservoir management and performance evaluation, (2) waterflood optimization, and (3) the demonstration of recovery processes involving off-the-shelf technologies which can be used to enhance waterflood recovery, increase reserves, and reduce the abandonment rate of these reservoir types. The reservoir management portion of the project will involve performance evaluation and will include such work as (1) reservoir characterization and the development of a reservoir database, (2) identification of operational problems, (3) identification of near wellbore problems, (4) identification of unrecovered mobile oil and estimation of recovery factors, and (5) identification of the most efficient and economical recovery process. The waterflood optimization portion of the project involves only the Nelson Lease. It will be based on the performance evaluation and will involve (1) design and implementation of a water cleanup system for the waterflood, (2) application of well remedial work such as polymer gel treatments to improve vertical sweep efficiency, and (3) changes in waterflood patterns to increase sweep efficiency. Finally, it is planned to implement an improved recovery process, possibly polymer augmented waterflood: on both field demonstration sites.

  20. Improved oil recovery in fluvial dominated deltaic reservoirs of Kansas -- near-term. Eighth quarterly report, April 1, 1995--June 30, 1995

    SciTech Connect (OSTI)

    Green, D.W.; Willhite, G.P.; Walton, A.; Schoeling, L.; Reynolds, R.; Michnick, M.; Watney, L.

    1995-07-15

    The objective of this project is to address waterflood problems of the type found in Cherokee Group reservoirs in southeastern Kansas and in Morrow sandstone reservoirs in southwestern Kansas. Two demonstration sites operated by different independent oil operators are involved in the project. The Nelson Lease (an existing waterflood) is located in Allen County, Kansas in the N.E. Savonburg Field and is operated by James E. Russell Petroleum, Inc. The Stewart Field (on latter stage of primary production) is located in Finney County, Kansas and is operated by North American Resources Company General topics to be addressed will be (1) reservoir management and performance evaluation, (2) waterflood optimization, and (3) the demonstration, of recovery processes involving off-the-shelf technologies which can be used to enhance waterflood recovery, increase reserves, and reduce the abandonment rate of these reservoir types. The reservoir management portion of the project will involve performance evaluation and will include such work as (1) reservoir characterization and the development of a reservoir database, (2) identification of operational problems, (3) identification of near wellbore problems, (4) identification of unrecovered mobile oil and estimation of recovery factors, and 5) identification of the most efficient and economical recovery process. The waterflood optimization portion of the project involves only the Nelson Lease. It will be based on the performance evaluation and will involve (1) design and implementation of a water cleanup system for the waterflood, (2) application of well remedial work such as polymer gel treatments to improve vertical sweep efficiency, and (3) changes in waterflood patterns to increase sweep efficiency. Finally, it is planned to implement an improved recovery process on both field demonstration sites.

  1. Improved oil recovery in fluvial dominated deltaic reservoirs of Kansas -- Near-term. Quarterly progress report, October 1--December 31, 1997

    SciTech Connect (OSTI)

    Green, D.W.; Willhite, G.P.; Walton, A.; McCune, D.; Reynolds, R.; Michnick, M.; Watney, L.

    1997-01-15

    The objective of this project is to address waterflood problems of the type found in Morrow sandstone reservoirs in southwestern Kansas and in Cherokee Group reservoirs in southeastern Kansas. Two demonstration sites operated by different independent oil operators are involved in this project. The Stewart Field is located in Finney County, Kansas and is operated by PetroSantander, Inc. The Nelson Lease is located in Allen County, Kansas, in the N.E. Savonburg Field and is operated by James E. Russell Petroleum, Inc. General topics to be addressed are (1) reservoir management and performance evaluation, (2) waterflood optimization, and (3) the demonstration of recovery processes involving off-the-shelf technologies which can be used to enhance waterflood recovery, increase reserves, and reduce the abandonment rate of these reservoir types. Progress in the Stewart field project is described for the following tasks: design/construct waterflood plant; design/construct injection system; design/construct battery consolidation and gathering system; waterflood operations and reservoir management; and technology transfer. Progress in the Savonburg field project is described for the following tasks: profile modification treatments; pattern changes and wellbore cleanup; reservoir development (polymer flooding); and technology transfer.

  2. Increased oil production and reserves utilizing secondary/tertiary recovery techniques on small reservoirs in the Paradox Basin, Utah. Annual report, February 9, 1997--February 8, 1998

    SciTech Connect (OSTI)

    Chidsey, T.C. Jr.

    1998-03-01

    The Paradox basin of Utah, Colorado, and Arizona contains nearly 100 small oil fields producing from carbonate buildups or mounds within the Pennsylvanian (Desmoinesian) Paradox Formation. These fields typically have one to four wells with primary production ranging from 700,000 to 2,000,000 barrels (111,300-318,000 m{sup 3}) of oil per field at a 15 to 20 percent recovery rate. At least 200 million barrels (31,800,000 m{sup 3}) of oil are at risk of being unrecovered in these small fields because of inefficient recovery practices and undrained heterogeneous reservoirs. Five fields (Anasazi, Mule, Blue Hogan, Heron North, and Runway) within the Navajo Nation of southeastern Utah are being evaluated for waterflood or carbon-dioxide (CO{sub 2})-miscible flood projects based upon geological characterization and reservoir modeling. The results can be applied to other fields in the Paradox basin and the Rocky Mountain region, the Michigan and Illinois basins, and the Midcontinent. Geological characterization on a local scale focused on reservoir heterogeneity, quality, and lateral continuity as well as possible compartmentalization within each of the five project fields. This study utilized representative core and modern geophysical logs to characterize and grade each of the five fields for suitability of enhanced recovery projects. The typical vertical sequence or cycle of lithofacies from each field, as determined from conventional core, was tied to its corresponding log response. The diagenetic fabrics and porosity types found in the various hydrocarbon-bearing rocks of each field can be an indicator of reservoir flow capacity, storage capacity, and potential for water- and/or CO{sub 2}-flooding. Diagenetic histories of the various Desert Creek reservoirs were determined from 50 representative samples selected from the conventional cores of each field. Thin sections were also made of each sample for petrographic description.

  3. Increased oil production and reserves utilizing secondary/teritiary recovery techniques on small reservoirs in the Paradox Basin, Utah. Quarterly report, July 1 - September 30, 1996

    SciTech Connect (OSTI)

    Allison, M.L.

    1996-10-01

    The primary objective of this project is to enhance domestic petroleum production by demonstration and technology transfer of an advanced oil recovery technology in the Paradox basin, southeastern Utah. If this project can demonstrate technical and economic feasibility, the technique can be applied to approximately 100 additional small fields in the Paradox basin alone, and result in increased recovery of 150 to 200 million barrels of oil. This project is designed to characterize five shallow-shelf carbonate reservoirs in the Pennsylvanian (Desmoinesian) Paradox Formation and choose the best candidate for a pilot demonstration project for either a waterflood or carbon dioxide flood project. The field demonstration, monitoring of field performance, and associated validation activities will take place in the Paradox basin within the Navajo Nation. The results of this project will be transferred to industry and other researchers through a petroleum extension service, creation of digital databases for distribution, technical workshops and seminars, field trips, technical presentations at national and regional professional meeting, and publication in newsletters and various technical or trade journals. Four activities continued this quarter as part of the geological and reservoir characterization: (1) interpretation of outcrop analogues; (2) reservoir mapping, (3) reservoir engineering analysis of the five project fields; and (4) technology transfer.

  4. Advanced oil recovery technologies for improved recovery from slope basin clastic reservoirs, Nash Draw Brushy Canyon Pool, Eddy County, NM. Quarterly technical progress report, October 1--December 31, 1995

    SciTech Connect (OSTI)

    1996-01-22

    Objective is to demonstrate that a development program based on advanced reservoir management methods can significantly improve oil recovery and to transfer this technology to oil and gas producers in the Permian Basin. The demonstration plan includes developing a control area using standard reservoir management techniques and comparing the performance of the control area with an area developed using advanced management methods. Specific goals are (1) to demonstrate that a development drilling program and pressure maintenance program, based on advanced reservoir management methods, can significantly improve oil recovery compared with existing technology applications, and (2) to transfer the advanced technologies to oil and gas producers in the Permian Basin and elswhere in the US oil and gas industry. This is the first quarterly progress report on the project; results to date are summarized.

  5. Increased oil production and reserves utilizing secondary/tertiary recovery techniques on small reservoirs in the Paradox basin, Utah. Final technical progress report, October 1--December 31, 1995

    SciTech Connect (OSTI)

    Allison, M.L.

    1996-01-15

    The primary objective of this project is to enhance domestic petroleum production by demonstration and technology transfer of an advanced oil recovery technology in the Paradox basin, southeastern Utah. If this project can demonstrate technical and economic feasibility, the technique can be applied to approximately 100 additional small fields in the Paradox basin alone, and result in increased recovery of 150 to 200 million barrels of oil. This project is designed to characterize five shallow-shelf carbonate reservoirs in the Pennsylvanian (Desmoinesian) Paradox Formation and choose the best candidate for a pilot demonstration project for either a waterflood or carbon dioxide-(CO{sub 2}) flood project. The field demonstration, monitoring of field performance, and associated validation activities will take place in the Paradox basin within the Navajo Nation. The results of this project will be transferred to industry and other researchers through a petroleum extension service, creation of digital databases for distribution, technical workshops and seminars, field trips, technical presentations at national and regional professional meeting, and publication in newsletters and various technical or trade journals. Five activities continued this quarter as part of the geological and reservoir characterization of carbonate mound buildups in the Paradox basin: (1) regional facies evaluation, (2) evaluation of outcrop analogues, (3) field-scale geologic analysis, (4) reservoir analysis, and (5) technology transfer.

  6. Increased oil production and reserves utilizing secondary/tertiary recovery techniques on small reservoirs in the Paradox basin, Utah. Technical progress report, July 1--September 30, 1995

    SciTech Connect (OSTI)

    Allison, M.L.

    1995-12-01

    The primary objective of this project is to enhance domestic petroleum production by demonstration and technology transfer of an advanced oil recovery technology in the Paradox basin, southeastern Utah. If this project can demonstrate technical and economic feasibility, the technique can be applied to approximately 100 additional small fields in the Paradox basin alone, and result in increased recovery of 150 to 200 million barrels of oil. This project is designed to characterize five shallow-shelf carbonate reservoirs in the Pennsylvanian (Desmoinesian) Paradox Formation and choose the best candidate for a pilot demonstration project for either a waterflood or carbon dioxide-(CO{sub 2}-) flood project. The field demonstration, monitoring of field performance, and associated validation activities will take place in the Paradox basin within the Navajo Nation. The results of this project will be transferred to industry and other researchers through a petroleum extension service, creation of digital databases for distribution, technical workshops and seminars, field trips, technical presentations at national and regional professional meetings, and publication in newsletters and various technical or trade journals. Four activities continued this quarter as part of the geological and reservoir characterization of carbonate mound buildups in the Paradox basin: (1) field studies, (2) development well completion operations, (3) reservoir analysis and modeling, and (4) technology transfer. This paper reviews the status.

  7. Increased oil production and reserves utilizing secondary/tertiary recovery techniques on small reservoirs in the Paradox basin, Utah. Quarterly report, October 1--December 31, 1996

    SciTech Connect (OSTI)

    Allison, M.L.

    1997-02-01

    The primary objective of this project is to enhance domestic petroleum production by demonstration and technology transfer of an advanced oil recovery technology in the Paradox basin, southeastern Utah. If this project can demonstrate technical and economic feasibility, the technique can be applied to approximately 100 additional small fields in the Paradox basin alone, and result in increased recovery of 150 to 200 million barrels of oil. This project is designed to characterize five shallow-shelf carbonate reservoirs in the Pennsylvanian (Desmoinesian) Paradox Formation and choose the best candidate for a pilot demonstration project for either a waterflood or carbon dioxide-(CO{sub 2}) flood project. The field demonstration, monitoring of field performance, and associated validation activities will take place in the Paradox basin within the Navajo Nation. The results of this project will be transferred to industry and other researchers through a petroleum extension service, creation of digital databases for distribution, technical workshops and seminars, field trips, technical presentations at national and regional professional meetings, and publication in newsletters and various technical or trade journals. Three activities continued this quarter as part of the geological and reservoir characterization of productive carbonate buidups in the Paradox basin: (1) interpretation of new seismic data in the Mule field area, (2) reservoir engineering analysis of the Anasazi field, and (3) technology transfer.

  8. Post waterflood CO{sub 2} miscible flood in light oil, fluvial-dominated deltaic reservoir. Annual report, fiscal year 1996

    SciTech Connect (OSTI)

    1996-08-15

    The Port Neches CO{sub 2} flood has been operating for nearly 4 years. The project performance during the past year has been adversely affected by several factors including: water blockage, low residual oil saturation and wellbore mechanical problems. The company attempted to test a new procedure in a new fault block using CO{sub 2} to accelerate primary production in order to improve the primary reserves net present value. The test was abandoned when the discovery well Polk B-39 for the Marg Area 3 was a dry hole. Also, during this period the company terminated all new CO{sub 2} purchases from Cardox for economical reasons, while continuing to recycle produced CO{sub 2}. A data base for FDD reservoirs for the Louisiana and Texas Gulf Coast Region was developed by LSU and SAIC. This data base includes reservoir parameters and performance data for reservoirs with significant production and OOIP volumes that are amenable to CO{sub 2} injection. A paper discussing the Port Neches CO{sub 2} project was presented at the 1996 SPE/DOE Symposium on Improved Oil Recovery.

  9. Advanced oil recovery technologies for improved recovery from slope basin clastic reservoirs, Nash Draw Brushy Canyon Pool, Eddy County, New Mexico. Annual report, September 25, 1995--September 24, 1996

    SciTech Connect (OSTI)

    Murphy, M.B.

    1997-08-01

    The basic driver for this project is the low recovery observed in Delaware reservoirs, such as the Nash Draw Pool (NDP). This low recovery is caused by low reservoir energy, less than optimum permeabilities and porosities, and inadequate reservoir characterization and reservoir management strategies which are typical of projects operated by independent producers. Rapid oil decline rates and high gas/oil ratios are typically observed in the first year of primary production. Based on the production characteristics that have been observed in similar Delaware fields, pressure maintenance is a likely requirement at the Nash Pool. Three basic constraints to producing the Nash Draw Brushy Canyon Reservoir are: (1) limited areal and interwell geologic knowledge, (2) lack of an engineering tool to evaluate the various producing strategies, and (3) limited surface access prohibiting development with conventional drilling. The limited surface access is caused by the proximity of underground potash mining and surface playa lakes. The objectives of this project are: (1) to demonstrate that a development drilling program and pressure maintenance program, based on advanced reservoir management methods, can significantly improve oil recovery compared with existing technology applications and (2) to transfer these advanced methodologies to oil and gas producers, especially in the Permian Basin.

  10. Increased oil production and reserves utilizing secondary/tertiary recovery techniques on small reservoirs in the Paradox Basin, Utah, Class II

    SciTech Connect (OSTI)

    Chidsey, Thomas C.

    2000-07-28

    The primary objective of this project is to enhance domestic petroleum production by field demonstration and technology transfer of an advanced-oil-recovery technology in the Paradox basin, southeastern Utah. If this project can demonstrate technical and economic feasibility, the technique can be applied to approximately 100 additional small fields in the Paradox basin alone, and result in increased recovery of 150 to 200 million barrels (23,850,000-31,800,000 m{sup 3}) of oil. This project is designed to characterize five shallow-shelf carbonate reservoirs in the Pennsylvanian (Desmoinesian) Paradox Formation and choose the best candidate for a pilot demonstration project for either a waterflood or carbon-dioxide-miscible flood project. The field demonstration, monitoring of field performance, and associated validation activities will take place within the Navajo Nation, San Juan County, Utah.

  11. DOE-Sponsored Field Test Demonstrates Viability of Simultaneous CO2 Storage and Enhanced Oil Recovery in Carbonate Reservoirs

    Broader source: Energy.gov [DOE]

    A field test conducted by a U.S. Department of Energy team of regional partners has demonstrated that using carbon dioxide in an enhanced oil recovery method dubbed "huff-and-puff" can help assess the carbon sequestration potential of geologic formations while tapping America's valuable oil resources.

  12. Depositional and diagenetic controls on porosity permeability and oil production in McFarland/Magutex (Queen) reservoirs, Andrews County, west Texas

    SciTech Connect (OSTI)

    Holtz, M.H. )

    1991-03-01

    The McFarland/Magutex Queen reservoir complex lies along the northeastern edge of the Central basin platform in the west Texas Permian basin and produces oil from the Permian Queen Formation. Current production from this complex totals 42 million stock-tank barrels (MMSTB) of an estimated 219 MMSTB of original oil in place, with an estimated 90 MMSTB of remaining mobile oil (RMO). The gross pay interval contains two parasequences consisting of progradational, 30-ft-thick, upward-shoaling facies packages. Facies include shoreface, mixed tidal channel and intertidal flat, and supratidal. Elongate shoreface facies are characterized by poorly consolidated, massive to thinly laminated sandstones. The supratidal facies, which act as permeability barriers, are characterized by algal-laminated dolostone and nodular, laminated, and massive anhydrite containing halite and gypsum pseudomorphs. Highest production and the largest amount of the 90 MMSTB of RMO is associated with the shoreface and tidal-channel facies. Bulk pore volume storage capacity and permeability are also highest within these two facies. Sandstones are arkosic, containing anhydrite and dolomite cements. Accessory minerals are clays, authigenic feldspar, and dolomite. Three main pore types are recognized: interparticle, moldic and intraconstituent, and micropores. Moldic and intraconstituent porosity is associated with leached feldspars and anhydrite cement dissolution. Microporosity is associated with syndepositional, grain-coating corrensite, dissolution-enhanced feldspar cleavage planes, and authigenic multifaceted dolomite. Microporosity derived from clays and dolomite is formed preferentially in tidal-channel and intertidal flat facies.

  13. Actualistic and Geochemical Modeling of Reservoir Rock, CO2 and Formation Fluid Interaction, Citronelle Oil Field, Alabama

    SciTech Connect (OSTI)

    Weislogel, Amy

    2014-01-31

    This report includes description of the Citronelle field study area and the work carried out in the project to characterize the geology and composition of reservoir rock material and to collect an analyze the geochemical composition of produced fluid waters from the Citronelle field. Reservoir rock samples collected from well bore core were made into thin-sections and assessed for textural properties, including pore types and porosity distribution. Compositional framework grain modal data were collected via point-counting, and grain and cement mineralogy was assessed using SEM-EDS. Geochemistry of fluid samples is described and modeled using PHREEQC. Composition of rock and produced fluids were used as inputs for TOUGHREACT reactive transport modeling, which determined the rock-fluid system was in disequilibrium.

  14. 5641_FrozenReservoirs | netl.doe.gov

    Broader source: All U.S. Department of Energy (DOE) Office Webpages (Extended Search)

    Little is known about how to produce conventional oil from a frozen reservoir. Most prior work has been on developing production techniques for heavy oil in unconsolidated but ...

  15. Oil

    Broader source: Energy.gov [DOE]

    The Energy Department works to ensure domestic and global oil supplies are environmentally sustainable and invests in research and technology to make oil drilling cleaner and more efficient.

  16. Reactivation of an Idle Lease to Increase Heavy Oil Recovery through Application of Conventional Steam Drive Technology in a Low Dip Slope and Basin Reservoir in the Midway-Sunset Field, San Jaoquin Basin, California

    SciTech Connect (OSTI)

    Steven Schamel

    1998-02-27

    A previously idle portion of the Midway-Sunset field, the ARCO Western Energy Pru Fee property, is being brought back into commercial production through tight integration of geologic characterization, geostatistical modeling, reservoir simulation, and petroleum engineering. This property, shut-in over a decade ago as economically marginal using conventional cyclic steaming methods, has a 200-300 foot thick oil column in the Monarch Sand. However, the sand lacks effective steam barriers and has a thick water-saturation zone above the oil-water contact. These factors require an innovative approach to steam flood production design that will balance optimal total oil production against economically viable steam-oil ratios and production rates. The methods used in the Class III demonstration are accessible to most operators in the Midway-Sunset field and could be used to revitalize properties with declining production of heavy oils throughout the region. In January 1997 the project entered its second and main phase with the purpose of demonstrating whether steamflood can be a more effective mode of production of the heavy, viscous oils from the Monarch Sand reservoir than the more conventional cyclic steaming. The objective is not just to produce the pilot site within the Pru Fee property south of Taft, but to test which production parameters optimize total oil recovery at economically acceptable rates of production and production costs.

  17. Increased oil production and reserves utilizing secondary/tertiary recovery techniques on small reservoirs in the Paradox basin, Utah. Technical progress report, April 1, 1995--June 30, 1995

    SciTech Connect (OSTI)

    Allison, M.L.

    1995-07-14

    The primary objective of this project is to enhance domestic petroleum production by demonstration and technology transfer of an advanced oil recovery technology in the Paradox basin, southeastern Utah. If this project can demonstrate technical and economic feasibility, the technique can be applied to approximately 100 additional small fields in the Paradox basin alone, and result in increased recovery of 150 to 200 million barrels of oil. This project is designed to characterize five shallow-shelf carbonate reservoirs in the Pennsylvanian (Desmoinesian) Paradox Formation and choose the best candidate for a pilot demonstration project for either a waterflood or carbon dioxide-flood project. The field demonstration, monitoring of field performance, and associated validation activities will take place in the Paradox basin within the Navajo Nation. The results of this project will be transferred to industry and other researchers through a petroleum extension service, creation of digital databases for distribution, technical workshops and seminars, field trips, technical presentations at national and regional professional meetings, and publication in newsletters and various technical or trade journals.

  18. Increased oil production and reserves utilizing secondary/tertiary recovery techniques on small reservoirs in the Paradox Basin, Utah. Technical progress report, January 1--March 31, 1996

    SciTech Connect (OSTI)

    Allison, M.L.

    1996-04-30

    The primary objective of this project is to enhance domestic petroleum production by demonstration and technology transfer of an advanced oil recovery technology in the Paradox basin, southeastern Utah. If this project can demonstrate technical and economic feasibility, the technique can be applied to approximately 100 additional small fields in the Paradox basin alone, and result in increased recovery of 150 to 200 million barrels of oil. This project is designed to characterize five shallow-shelf carbonate reservoirs in the Pennsylvanian (Desmoinesian) Paradox Formation and choose the best candidate for a pilot demonstration project for either a waterflood or carbon dioxide-(CO{sub 2}-)flood project. The field demonstration, monitoring of field performance, and associated validation activities will take place in the Paradox basin within the Navajo Nation. The results of this project will be transferred to industry and other researchers through a petroleum extension service, creation of digital databases for distribution, technical workshops and seminars, field trips, technical presentations at national and regional professional meetings, and publication in newsletters and various technical or trade journals.

  19. Increased oil production and reserves utilizing secondary/tertiary recovery techniques on small reservoirs in the Paradox basin, Utah. Technical progress report, January 1, 1995--March 31, 1995

    SciTech Connect (OSTI)

    Allison, M.L.

    1995-05-30

    The primary objective of this project is to enhance domestic petroleum production by demonstration and technology transfer of an advanced oil recovery technology in the Paradox basin, southeastern Utah. If this project can demonstrate technical and economic feasibility, the technique can be applied to approximately 100 additional small fields in the Paradox basin alone, and result in increased recovery of 150 to 200 million barrels of oil. This project is designed to characterize five shallow-shelf carbonate reservoirs in the Pennsylvanian Paradox Formation and choose the best candidate for a pilot demonstration project for either a waterflood or carbon dioxide-flood project. The field demonstration, monitoring of field performance, and associated validation activities will take place in the Paradox basin within the Navajo Nation. The results of this project will be transferred to industry and other researchers through a petroleum extension service, creation of digital databases for distribution, technical workshops and seminars, field trips, technical presentations at national and regional professional meetings, and publication in newsletters and various technical or trade journals.

  20. Oil recovery enhancement from fractured, low permeability reservoirs. Part 2, Annual report, October 1, 1990--September 31, 1991

    SciTech Connect (OSTI)

    Poston, S.W.

    1991-12-31

    The results of the investigative efforts for this jointly funded DOE-State of Texas research project achieved during the 1990--1991 year may be summarized as follows: Geological Characterization -- Detailed maps of the development and hierarchical nature the fracture system exhibited by Austin Chalk outcrops were prepared. These results of these efforts were directly applied to the development of production decline type curves applicable to a dual fracture-matrix flow system. Analysis of production records obtained from Austin Chalk operators illustrated the utility of these type curves to determine relative fracture/matrix contributions and extent. Well-log response in Austin Chalk wells has been shown to be a reliable indicator of organic maturity. (VSP) Vertical-Seismic Profile data was used to use shear-wave splitting concepts to estimate fracture orientations. Several programs were to be written to facilitate analysis of the data. The results of these efforts indicated fractures could be detected with VSP seismic methods. Development of the (EOR) Enhanced Oil Recovery Imbibition Process -- Laboratory displacement as well as MRI and CT imaging studies have shown the carbonated water-imbibition displacement process significantly accelerates and increases recovery of an oil saturated, low permeability core material, when compared to that of a normal brine imbibition displacement process. A study of oil recovery by the application of a cyclic carbonated water imbibition process, followed by reducing the pressure below the bubble point of the CO{sub 2}-water solution, indicated the possibility of alternate and new enhanced recovery method. The installation of an artificial solution gas drive significantly increased oil recovery. The extent and arrangement of micro-fractures in Austin Chalk horizontal cores was mapped with CT scanning techniques. The degree of interconnection of the micro-fractures was easily visualized.

  1. Utah Heavy Oil Program

    SciTech Connect (OSTI)

    J. Bauman; S. Burian; M. Deo; E. Eddings; R. Gani; R. Goel; C.K. Huang; M. Hogue; R. Keiter; L. Li; J. Ruple; T. Ring; P. Rose; M. Skliar; P.J. Smith; J.P. Spinti; P. Tiwari; J. Wilkey; K. Uchitel

    2009-10-20

    The Utah Heavy Oil Program (UHOP) was established in June 2006 to provide multidisciplinary research support to federal and state constituents for addressing the wide-ranging issues surrounding the creation of an industry for unconventional oil production in the United States. Additionally, UHOP was to serve as an on-going source of unbiased information to the nation surrounding technical, economic, legal and environmental aspects of developing heavy oil, oil sands, and oil shale resources. UHOP fulGilled its role by completing three tasks. First, in response to the Energy Policy Act of 2005 Section 369(p), UHOP published an update report to the 1987 technical and economic assessment of domestic heavy oil resources that was prepared by the Interstate Oil and Gas Compact Commission. The UHOP report, entitled 'A Technical, Economic, and Legal Assessment of North American Heavy Oil, Oil Sands, and Oil Shale Resources' was published in electronic and hard copy form in October 2007. Second, UHOP developed of a comprehensive, publicly accessible online repository of unconventional oil resources in North America based on the DSpace software platform. An interactive map was also developed as a source of geospatial information and as a means to interact with the repository from a geospatial setting. All documents uploaded to the repository are fully searchable by author, title, and keywords. Third, UHOP sponsored Give research projects related to unconventional fuels development. Two projects looked at issues associated with oil shale production, including oil shale pyrolysis kinetics, resource heterogeneity, and reservoir simulation. One project evaluated in situ production from Utah oil sands. Another project focused on water availability and produced water treatments. The last project considered commercial oil shale leasing from a policy, environmental, and economic perspective.

  2. ADVANCED RESERVOIR CHARACTERIZATION IN THE ANTELOPE SHALE TO ESTABLISH THE VIABILITY OF CO2 ENHANCED OIL RECOVERY IN CALIFORNIA'S MONTEREY FORMATION SILICEOUS SHALES

    SciTech Connect (OSTI)

    Pasquale R. Perri

    2003-05-15

    This report describes the evaluation, design, and implementation of a DOE funded CO{sub 2} pilot project in the Lost Hills Field, Kern County, California. The pilot consists of four inverted (injector-centered) 5-spot patterns covering approximately 10 acres, and is located in a portion of the field, which has been under waterflood since early 1992. The target reservoir for the CO{sub 2} pilot is the Belridge Diatomite. The pilot location was selected based on geologic considerations, reservoir quality and reservoir performance during the waterflood. A CO{sub 2} pilot was chosen, rather than full-field implementation, to investigate uncertainties associated with CO{sub 2} utilization rate and premature CO{sub 2} breakthrough, and overall uncertainty in the unproven CO{sub 2} flood process in the San Joaquin Valley. A summary of the design and objectives of the CO{sub 2} pilot are included along with an overview of the Lost Hills geology, discussion of pilot injection and production facilities, and discussion of new wells drilled and remedial work completed prior to commencing injection. Actual CO{sub 2} injection began on August 31, 2000 and a comprehensive pilot monitoring and surveillance program has been implemented. Since the initiation of CO{sub 2} injection, the pilot has been hampered by excessive sand production in the pilot producers due to casing damage related to subsidence and exacerbated by the injected CO{sub 2}. Therefore CO{sub 2} injection was very sporadic in 2001 and 2002 and we experienced long periods of time with no CO{sub 2} injection. As a result of the continued mechanical problems, the pilot project was terminated on January 30, 2003. This report summarizes the injection and production performance and the monitoring results through December 31, 2002 including oil geochemistry, CO{sub 2} injection tracers, crosswell electromagnetic surveys, crosswell seismic, CO{sub 2} injection profiling, cased hole resistivity, tiltmetering results, and corrosion monitoring results. Although the Lost Hills CO{sub 2} pilot was not successful, the results and lessons learned presented in this report may be applicable to evaluate and design other potential San Joaquin Valley CO{sub 2} floods.

  3. Reservoir Claddings

    SciTech Connect (OSTI)

    2009-05-14

    This information sheet explains how to properly decouple reservoir claddings from water sensitive materials of the wall assembly.

  4. Improved oil recovery in Mississippian carbonate reservoirs of Kansas - near term -- Class 2. Quarterly progress report, July 1, 1995--September 30, 1995

    SciTech Connect (OSTI)

    Carr, T.; Green, D.W.; Willhite, G.P.

    1995-11-01

    The objective of this project is to demonstrate incremental reserves from Osagian and Meramecian dolomite reservoirs in western Kansas through application of reservoir characterization to identify areas of unrecovered mobile petroleum. Specific reservoirs targeted are the Schaben Field in Ness County and the Bindley Field in Hodgeman County.

  5. Enhanced oil recovery

    SciTech Connect (OSTI)

    Fisher, W.G.

    1982-01-01

    The principal enhanced recovery technique is waterflooding, because water generally is inexpensive to obtain and inject into the reservoir and it works. With the shortage of conventional oil in Canada there is greater emphasis being placed on other recovery schemes in addition to or in place of waterflooding. Tertiary recovery is applicable to many of the existing projects and engineers must recognize those fields that are candidates for tertiary recovery applications. The application of tertiary recovery techniques to a specific reservoir requires consideration of all methods developed to select the one most suitable. A thorough understanding of waterflooding and the factors that affect recovery is necessary before a tertiary process is considered. Factors that affect oil recovery under waterflooding are areal and vertical sweep efficiency, contact factor and displacement efficiency.

  6. Texas--RRC District 3 Onshore Crude Oil Reserves in Nonproducing...

    Annual Energy Outlook [U.S. Energy Information Administration (EIA)]

    Crude Oil Reserves in Nonproducing Reservoirs (Million Barrels) Texas--RRC District 3 Onshore Crude Oil Reserves in Nonproducing Reservoirs (Million Barrels) Decade Year-0 Year-1 ...

  7. Texas--RRC District 2 Onshore Crude Oil Reserves in Nonproducing...

    Annual Energy Outlook [U.S. Energy Information Administration (EIA)]

    Crude Oil Reserves in Nonproducing Reservoirs (Million Barrels) Texas--RRC District 2 Onshore Crude Oil Reserves in Nonproducing Reservoirs (Million Barrels) Decade Year-0 Year-1 ...

  8. Texas--RRC District 4 Onshore Crude Oil Reserves in Nonproducing...

    Annual Energy Outlook [U.S. Energy Information Administration (EIA)]

    Crude Oil Reserves in Nonproducing Reservoirs (Million Barrels) Texas--RRC District 4 Onshore Crude Oil Reserves in Nonproducing Reservoirs (Million Barrels) Decade Year-0 Year-1 ...

  9. Advanced reservoir characterization in the Antelope Shale to establish the viability of CO2 enhanced oil recovery in California`s Monterey Formation siliceous shales. Annual report, February 7, 1997--February 6, 1998

    SciTech Connect (OSTI)

    Morea, M.F.

    1998-06-01

    The primary objective of this research is to conduct advanced reservoir characterization and modeling studies in the Antelope Shale reservoir. Characterization studies will be used to determine the technical feasibility of implementing a CO{sub 2} enhanced oil recovery project in the antelope Shale in Buena Vista Hills Field. The proposed pilot consists of four existing producers on 20 acre spacing with a new 10 acre infill well drilled as the pilot CO{sub 2} injector. Most of the reservoir characterization during Phase 1 of the project will be performed using data collected in the pilot pattern wells. During this period the following tasks have been completed: laboratory wettability; specific permeability; mercury porosimetry; acoustic anisotropy; rock mechanics analysis; core description; fracture analysis; digital image analysis; mineralogical analysis; hydraulic flow unit analysis; petrographic and confocal thin section analysis; oil geochemical fingerprinting; production logging; carbon/oxygen logging; complex lithologic log analysis; NMR T2 processing; dipole shear wave anisotropy logging; shear wave vertical seismic profile processing; structural mapping; and regional tectonic synthesis. Noteworthy technological successes for this reporting period include: (1) first (ever) high resolution, crosswell reflection images of SJV sediments; (2) first successful application of the TomoSeis acquisition system in siliceous shales; (3) first detailed reservoir characterization of SJV siliceous shales; (4) first mineral based saturation algorithm for SJV siliceous shales, and (5) first CO{sub 2} coreflood experiments for siliceous shale. Preliminary results from the CO{sub 2} coreflood experiments (2,500 psi) suggest that significant oil is being produced from the siliceous shale.

  10. Oil & Gas Research

    Broader source: All U.S. Department of Energy (DOE) Office Webpages (Extended Search)

    needed to predict and quantify potential risks associated with oil and gas resources in shale reservoirs that require hydraulic fracturing or other engineering measures to produce. ...

  11. Development of Reservoir Characterization Techniques and Production Models for Exploiting Naturally Fractured Reservoirs

    SciTech Connect (OSTI)

    Wiggins, Michael L.; Brown, Raymon L.; Civan, Faruk; Hughes, Richard G.

    2003-02-11

    This research was directed toward developing a systematic reservoir characterization methodology which can be used by the petroleum industry to implement infill drilling programs and/or enhanced oil recovery projects in naturally fractured reservoir systems in an environmentally safe and cost effective manner. It was anticipated that the results of this research program will provide geoscientists and engineers with a systematic procedure for properly characterizing a fractured reservoir system and a reservoir/horizontal wellbore simulator model which can be used to select well locations and an effective EOR process to optimize the recovery of the oil and gas reserves from such complex reservoir systems.

  12. DOE - Fossil Energy: Washing More Oil from Rocks

    Broader source: All U.S. Department of Energy (DOE) Office Webpages (Extended Search)

    That's exactly what oil producers do in an oil reservoir. They drill wells called "injection wells" and use them like gigantic hoses to pump water into an oil reservoir. The water ...

  13. Reactivation of an idle lease to increase heavy oil recovery through application of conventional steam drive technology in a low dip slope and basin reservoir in the Midway-Sunset field, San Jaoquin Basin, California. Annual report, June 13, 1995--June 13, 1996

    SciTech Connect (OSTI)

    Deo, M.; Jenkins, C.; Sprinkel, D.; Swain, R.; Wydrinski, R.; Schamel, S.

    1998-09-01

    This project reactivates ARCO`s idle Pru Fee lease in the Midway-Sunset field, California and conducts a continuous steamflood enhanced oil recovery demonstration aided by an integration of modern reservoir characterization and simulation methods. Cyclic steaming is being used to reestablish baseline production within the reservoir characterization phase of the project. During the demonstration phase scheduled to begin in January 1997, a continuous steamflood enhanced oil recovery will be initiated to test the incremental value of this method as an alternative to cyclic steaming. Other economically marginal Class III reservoirs having similar producibility problems will benefit from insight gained in this project. The objectives of the project are: (1) to return the shut-in portion of the reservoir to optimal commercial production; (2) to accurately describe the reservoir and recovery process; and (3) to convey the details of this activity to the domestic petroleum industry, especially to other producers in California, through an aggressive technology transfer program.

  14. DOE - Fossil Energy: Soap, Bugs and Other Ways to Produce Oil

    Broader source: All U.S. Department of Energy (DOE) Office Webpages (Extended Search)

    It hardly flows out of a jar, much less out of an oil reservoir. But if the oil is heated, it becomes thinner and more slippery. To heat heavy oil in a reservoir, oil companies ...

  15. DOE - Office of Legacy Management -- Pantex Sewage Reservoir...

    Office of Legacy Management (LM)

    Pantex Sewage Reservoir - TX 03 FUSRAP Considered Sites Site: Pantex Sewage Reservoir (TX.03 ) Designated Name: Alternate Name: Location: Evaluation Year: Site Operations: Site...

  16. Chemical Methods for Ugnu Viscous Oils

    SciTech Connect (OSTI)

    Kishore Mohanty

    2012-03-31

    The North Slope of Alaska has large (about 20 billion barrels) deposits of viscous oil in Ugnu, West Sak and Shraeder Bluff reservoirs. These shallow reservoirs overlie existing productive reservoirs such as Kuparuk and Milne Point. The viscosity of the Ugnu reservoir on top of Milne Point varies from 200 cp to 10,000 cp and the depth is about 3300 ft. The same reservoir extends to the west on the top of the Kuparuk River Unit and onto the Beaufort Sea. The depth of the reservoir decreases and the viscosity increases towards the west. Currently, the operators are testing cold heavy oil production with sand (CHOPS) in Ugnu, but oil recovery is expected to be low (< 10%). Improved oil recovery techniques must be developed for these reservoirs. The proximity to the permafrost is an issue for thermal methods; thus nonthermal methods must be considered. The objective of this project is to develop chemical methods for the Ugnu reservoir on the top of Milne Point. An alkaline-surfactant-polymer (ASP) formulation was developed for a viscous oil (330 cp) where as an alkaline-surfactant formulation was developed for a heavy oil (10,000 cp). These formulations were tested in one-dimensional and quarter five-spot Ugnu sand packs. Micromodel studies were conducted to determine the mechanisms of high viscosity ratio displacements. Laboratory displacements were modeled and transport parameters (such as relative permeability) were determined that can be used in reservoir simulations. Ugnu oil is suitable for chemical flooding because it is biodegraded and contains some organic acids. The acids react with injected alkali to produce soap. This soap helps in lowering interfacial tension between water and oil which in turn helps in the formation of macro and micro emulsions. A lower amount of synthetic surfactant is needed because of the presence of organic acids in the oil. Tertiary ASP flooding is very effective for the 330 cp viscous oil in 1D sand pack. This chemical formulation includes 1.5% of an alkali, 0.4% of a nonionic surfactant, and 0.48% of a polymer. The secondary waterflood in a 1D sand pack had a cumulative recovery of 0.61 PV in about 3 PV injection. The residual oil saturation to waterflood was 0.26. Injection of tertiary alkaline-surfactant-polymer slug followed by tapered polymer slugs could recover almost 100% of the remaining oil. The tertiary alkali-surfactant-polymer flood of the 330 cp oil is stable in three-dimensions; it was verified by a flood in a transparent 5-spot model. A secondary polymer flood is also effective for the 330 cp viscous oil in 1D sand pack. The secondary polymer flood recovered about 0.78 PV of oil in about 1 PV injection. The remaining oil saturation was 0.09. The pressure drops were reasonable (<2 psi/ft) and depended mainly on the viscosity of the polymer slug injected. For the heavy crude oil (of viscosity 10,000 cp), low viscosity (10-100 cp) oil-in-water emulsions can be obtained at salinity up to 20,000 ppm by using a hydrophilic surfactant along with an alkali at a high water-to-oil ratio of 9:1. Very dilute surfactant concentrations (~0.1 wt%) of the synthetic surfactant are required to generate the emulsions. It is much easier to flow the low viscosity emulsion than the original oil of viscosity 10,000 cp. Decreasing the WOR reverses the type of emulsion to water-in-oil type. For a low salinity of 0 ppm NaCl, the emulsion remained O/W even when the WOR was decreased. Hence a low salinity injection water is preferred if an oil-in-water emulsion is to be formed. Secondary waterflood of the 10,000 cp heavy oil followed by tertiary injection of alkaline-surfactants is very effective. Waterflood has early water breakthrough, but recovers a substantial amount of oil beyond breakthrough. Waterflood recovers 20-37% PV of the oil in 1D sand pack in about 3 PV injection. Tertiary alkali-surfactant injection increases the heavy oil recovery to 50-70% PV in 1D sand packs. As the salinity increased, the oil recovery due to alkaline surfactant flood increased, but water-in-oil emulsion was produced and pressure drop increased. With low salinity (deionized) water, the oil recovery was lower, but so was the pressure drop because only oil-in-water emulsion was produced. Secondary waterflood of the 10,000 cp heavy oil in 5-spot sand packs recovers 30-35% OOIP of the oil in about 2.5 PV injection. Tertiary injection of the alkaline-surfactant solution increases the cumulative oil recovery from 51 to 57% OOIP in 5-spot sand packs. As water displaces the heavy oil, it fingers through the oil with a fractal structure (fractal dimension = 1.6), as seen in the micromodel experiments. Alkaline-surfactant solution emulsifies the oil around the brine fingers and flows them to the production well. A fractional flow model incorporating the effect of viscous fingering was able to match the laboaratory experiments and can be used in reservoir simulators. The chemical techniques look promising in the laboratory and should be tested in the fields.

  17. US production of natural gas from tight reservoirs

    SciTech Connect (OSTI)

    Not Available

    1993-10-18

    For the purposes of this report, tight gas reservoirs are defined as those that meet the Federal Energy Regulatory Commission`s (FERC) definition of tight. They are generally characterized by an average reservoir rock permeability to gas of 0.1 millidarcy or less and, absent artificial stimulation of production, by production rates that do not exceed 5 barrels of oil per day and certain specified daily volumes of gas which increase with the depth of the reservoir. All of the statistics presented in this report pertain to wells that have been classified, from 1978 through 1991, as tight according to the FERC; i.e., they are ``legally tight`` reservoirs. Additional production from ``geologically tight`` reservoirs that have not been classified tight according to the FERC rules has been excluded. This category includes all producing wells drilled into legally designated tight gas reservoirs prior to 1978 and all producing wells drilled into physically tight gas reservoirs that have not been designated legally tight. Therefore, all gas production referenced herein is eligible for the Section 29 tax credit. Although the qualification period for the credit expired at the end of 1992, wells that were spudded (began to be drilled) between 1978 and May 1988, and from November 5, 1990, through year end 1992, are eligible for the tax credit for a subsequent period of 10 years. This report updates the EIA`s tight gas production information through 1991 and considers further the history and effect on tight gas production of the Federal Government`s regulatory and tax policy actions. It also provides some high points of the geologic background needed to understand the nature and location of low-permeability reservoirs.

  18. The role of reservoir characterization in the reservoir management process (as reflected in the Department of Energy`s reservoir management demonstration program)

    SciTech Connect (OSTI)

    Fowler, M.L.; Young, M.A.; Madden, M.P.

    1997-08-01

    Optimum reservoir recovery and profitability result from guidance of reservoir practices provided by an effective reservoir management plan. Success in developing the best, most appropriate reservoir management plan requires knowledge and consideration of (1) the reservoir system including rocks, and rock-fluid interactions (i.e., a characterization of the reservoir) as well as wellbores and associated equipment and surface facilities; (2) the technologies available to describe, analyze, and exploit the reservoir; and (3) the business environment under which the plan will be developed and implemented. Reservoir characterization is the essential to gain needed knowledge of the reservoir for reservoir management plan building. Reservoir characterization efforts can be appropriately scaled by considering the reservoir management context under which the plan is being built. Reservoir management plans de-optimize with time as technology and the business environment change or as new reservoir information indicates the reservoir characterization models on which the current plan is based are inadequate. BDM-Oklahoma and the Department of Energy have implemented a program of reservoir management demonstrations to encourage operators with limited resources and experience to learn, implement, and disperse sound reservoir management techniques through cooperative research and development projects whose objectives are to develop reservoir management plans. In each of the three projects currently underway, careful attention to reservoir management context assures a reservoir characterization approach that is sufficient, but not in excess of what is necessary, to devise and implement an effective reservoir management plan.

  19. Advanced Reservoir Characterization in the Antelope Shale to Establish the Viability of CO2 Enhanced Oil Recovery in California's Monterey Formation Siliceous Shales, Class III

    SciTech Connect (OSTI)

    Perri, Pasquale R.

    2001-04-04

    This report describes the evaluation, design, and implementation of a DOE funded CO2 pilot project in the Lost Hills Field, Kern County, California. The pilot consists of four inverted (injector-centered) 5-spot patterns covering approximately 10 acres, and is located in a portion of the field, which has been under waterflood since early 1992. The target reservoir for the CO2 pilot is the Belridge Diatomite. The pilot location was selected based on geology, reservoir quality and reservoir performance during the waterflood. A CO2 pilot was chosen, rather than full-field implementation, to investigate uncertainties associated with CO2 utilization rate and premature CO2 breakthrough, and overall uncertainty in the unproven CO2 flood process in the San Joaquin Valley.

  20. Analysis of real-time reservoir monitoring : reservoirs, strategies, & modeling.

    SciTech Connect (OSTI)

    Mani, Seethambal S.; van Bloemen Waanders, Bart Gustaaf; Cooper, Scott Patrick; Jakaboski, Blake Elaine; Normann, Randy Allen; Jennings, Jim; Gilbert, Bob; Lake, Larry W.; Weiss, Chester Joseph; Lorenz, John Clay; Elbring, Gregory Jay; Wheeler, Mary Fanett; Thomas, Sunil G.; Rightley, Michael J.; Rodriguez, Adolfo; Klie, Hector; Banchs, Rafael; Nunez, Emilio J.; Jablonowski, Chris

    2006-11-01

    The project objective was to detail better ways to assess and exploit intelligent oil and gas field information through improved modeling, sensor technology, and process control to increase ultimate recovery of domestic hydrocarbons. To meet this objective we investigated the use of permanent downhole sensors systems (Smart Wells) whose data is fed real-time into computational reservoir models that are integrated with optimized production control systems. The project utilized a three-pronged approach (1) a value of information analysis to address the economic advantages, (2) reservoir simulation modeling and control optimization to prove the capability, and (3) evaluation of new generation sensor packaging to survive the borehole environment for long periods of time. The Value of Information (VOI) decision tree method was developed and used to assess the economic advantage of using the proposed technology; the VOI demonstrated the increased subsurface resolution through additional sensor data. Our findings show that the VOI studies are a practical means of ascertaining the value associated with a technology, in this case application of sensors to production. The procedure acknowledges the uncertainty in predictions but nevertheless assigns monetary value to the predictions. The best aspect of the procedure is that it builds consensus within interdisciplinary teams The reservoir simulation and modeling aspect of the project was developed to show the capability of exploiting sensor information both for reservoir characterization and to optimize control of the production system. Our findings indicate history matching is improved as more information is added to the objective function, clearly indicating that sensor information can help in reducing the uncertainty associated with reservoir characterization. Additional findings and approaches used are described in detail within the report. The next generation sensors aspect of the project evaluated sensors and packaging survivability issues. Our findings indicate that packaging represents the most significant technical challenge associated with application of sensors in the downhole environment for long periods (5+ years) of time. These issues are described in detail within the report. The impact of successful reservoir monitoring programs and coincident improved reservoir management is measured by the production of additional oil and gas volumes from existing reservoirs, revitalization of nearly depleted reservoirs, possible re-establishment of already abandoned reservoirs, and improved economics for all cases. Smart Well monitoring provides the means to understand how a reservoir process is developing and to provide active reservoir management. At the same time it also provides data for developing high-fidelity simulation models. This work has been a joint effort with Sandia National Laboratories and UT-Austin's Bureau of Economic Geology, Department of Petroleum and Geosystems Engineering, and the Institute of Computational and Engineering Mathematics.

  1. Microbial enhanced oil recovery and compositions therefor

    DOE Patents [OSTI]

    Bryant, Rebecca S.

    1990-01-01

    A method is provided for microbial enhanced oil recovery, wherein a combination of microorganisms is empirically formulated based on survivability under reservoir conditions and oil recovery efficiency, such that injection of the microbial combination may be made, in the presence of essentially only nutrient solution, directly into an injection well of an oil bearing reservoir having oil present at waterflood residual oil saturation concentration. The microbial combination is capable of displacing residual oil from reservoir rock, which oil may be recovered by waterflooding without causing plugging of the reservoir rock. Further, the microorganisms are capable of being transported through the pores of the reservoir rock between said injection well and associated production wells, during waterflooding, which results in a larger area of the reservoir being covered by the oil-mobilizing microorganisms.

  2. Post waterflood CO{sub 2} miscible flood in light oil, fluvial: Dominated deltaic reservoir. First quarterly technical progress report, Fiscal year 1994, October 1, 1993--December 31, 1993

    SciTech Connect (OSTI)

    Not Available

    1994-01-15

    Production from the Port Neches CO{sub 2} project was initiated on December 6, 1993 after having been shut-in since the start of CO{sub 2} injection on September 22, 1993 to allow reservoir pressure to build. Rates were established at 236 barrels of oil per day (BOPD) from two wells in the 235 acre waterflood project area, which before project initiation had produced only 80 BOPD from the entire area. These wells are flowing large amounts of fluid due to the high reservoir pressure and their oil percentages are increasing as a result of the CO{sub 2} contacting the residual oil. One well, the H. J. Kuhn No. 15-R is flowing 217 BOPD, 1139 BWPD, and 2500 MCFPD of CO{sub 2} at a flowing tubing pressure (FTP) of 890 psi. The other producing well, the H. J. Kuhn No. 33, is currently flowing 19 BOPD, 614 BWPD, and 15 MCFPD at a FTP of 400 psi. Unexpectedly high rates of CO{sub 2} production are being made from Well No. 15-R and from the W. R. Stark ``B`` No. 8. This No. 8 well produced 7 BOPD, 697 BWPD, and 15 MCFPD prior to being shut-in during September to allow for the reservoir pressure to build by injecting CO{sub 2}, but when opened on December 6, the well flowed dry CO{sub 2} at a rate of 400 MCFPD for a two day test period. More sustained production tests will be obtained after all wells are tied into the new production facility. Many difficulties occurred in the drilling of the horizontal CO{sub 2} injection well but a successful completion across 2501 of sand has finally been accomplished. A formation dip of 11--14 degrees in the area where the well was being drilled made the proposed 1500{prime} horizontal sand section too difficult to accomplish. The shale section directly above the sand caused sticking problems on two separate occasions resulting in two sidetracks of the well around stuck pipe. The well will be tied into the facility and CO{sub 2} injection into the well will begin before February 1, 1994.

  3. Biochemically enhanced oil recovery and oil treatment

    DOE Patents [OSTI]

    Premuzic, Eugene T.; Lin, Mow

    1994-01-01

    This invention relates to the preparation of new, modified organisms, through challenge growth processes, that are viable in the extreme temperature, pressure and pH conditions and salt concentrations of an oil reservoir and that are suitable for use in microbial enhanced oil recovery. The modified microorganisms of the present invention are used to enhance oil recovery and remove sulfur compounds and metals from the crude oil.

  4. Biochemically enhanced oil recovery and oil treatment

    DOE Patents [OSTI]

    Premuzic, E.T.; Lin, M.

    1994-03-29

    This invention relates to the preparation of new, modified organisms, through challenge growth processes, that are viable in the extreme temperature, pressure and pH conditions and salt concentrations of an oil reservoir and that are suitable for use in microbial enhanced oil recovery. The modified microorganisms of the present invention are used to enhance oil recovery and remove sulfur compounds and metals from the crude oil. 62 figures.

  5. Texas (with State Offshore) Crude Oil Reserves in Nonproducing...

    Annual Energy Outlook [U.S. Energy Information Administration (EIA)]

    Crude Oil Reserves in Nonproducing Reservoirs (Million Barrels) Texas (with State ... Referring Pages: Proved Nonproducing Reserves of Crude Oil Texas Proved Nonproducing ...

  6. California Division of Oil, Gas, and Geothermal Resources | Open...

    Open Energy Info (EERE)

    reservoirs. Division requirements encourage wise development of California's oil, gas, and geothermal resources while protecting the environment.2 References "CDOGGR...

  7. Innovative MIOR Process Utilizing Indigenous Reservoir Constituents

    SciTech Connect (OSTI)

    Hitzman, D.O.; Stepp, A.K.; Dennis, D.M.; Graumann, L.R.

    2003-02-11

    This research program was directed at improving the knowledge of reservoir ecology and developing practical microbial solutions for improving oil production. The goal was to identify indigenous microbial populations which can produce beneficial metabolic products and develop a methodology to stimulate those select microbes with inorganic nutrient amendments to increase oil recovery. This microbial technology has the capability of producing multiple oil-releasing agents.

  8. Increased oil production and reserves utilizing secondary/tertiary recovery techniques on small reservoirs in the Paradox basin, Utah. Quarterly technical progress report, April 1, 1996--June 30, 1996

    SciTech Connect (OSTI)

    Allison, M.L.

    1996-08-01

    The primary objective of this project is to enhance domestic petroleum production by demonstration and technology transfer of an advanced oil recovery technology in the Paradox basin, southeastern Utah. If this project can demonstrate technical and economic feasibility, the technique can be applied to approximately 100 additional small fields in the Paradox basin alone, and result in increased recovery of 150 to 200 million barrels of oil. This project is designed to characterize five shallow-shelf carbonate reservoirs in the Pennsylvanian (Desmoinesian) Paradox Formation and choose the best candidate for a pilot demonstration project for either a waterflood or carbon dioxide (CO{sub 2}-)flood project. The field demonstration, monitoring of field performance, and associated validation activities will take place in the Paradox basin within the Navajo Nation. The results of this project will be transferred to industry and other researchers through a petroleum extension service, creation of digital databases for distribution, technical workshops and seminars, field trips, technical presentations at national and regional professional meetings, and publication in newsletters and various technical or trade journals.

  9. Reservoir Characterization, Production Characteristics, and Research Needs for Fluvial/Alluvial Reservoirs in the United States

    SciTech Connect (OSTI)

    Cole, E.L.; Fowler, M.L.; Jackson, S.R.; Madden, M.P.; Raw-Schatzinger, V.; Salamy, S.P.; Sarathi, P.; Young, M.A.

    1999-04-28

    The Department of Energy's (DOE's) Oil Recovery Field Demonstration Program was initiated in 1992 to maximize the economically and environmentally sound recovery of oil from known domestic reservoirs and to preserve access to this resource. Cost-shared field demonstration projects are being initiated in geology defined reservoir classes which have been prioritized by their potential for incremental recovery and their risk of abandonment. This document defines the characteristics of the fifth geological reservoir class in the series, fluvial/alluvial reservoirs. The reservoirs of Class 5 include deposits of alluvial fans, braided streams, and meandering streams. Deposit morphologies vary as a complex function of climate and tectonics and are characterized by a high degree of heterogeneity to fluid flow as a result of extreme variations in water energy as the deposits formed.

  10. Water Influx, and Its Effect on Oil Recovery: Part 1. Aquifer Flow, SUPRI TR-103

    SciTech Connect (OSTI)

    Brigham, William E.

    1999-08-09

    Natural water encroachment is commonly seen in many oil and gas reservoirs. In fact, overall, there is more water than oil produced from oil reservoirs worldwide. Thus it is clear that an understanding of reservoir/aquifer interaction can be an important aspect of reservoir management to optimize recovery of hydrocarbons. Although the mathematics of these processes are difficult, they are often amenable to analytical solution and diagnosis. Thus this will be the ultimate goal of a series of reports on this subject. This first report deals only with aquifer behavior, so it does not address these important reservoir/aquifer issues. However, it is an important prelude to them, for the insight gained gives important clues on how to address reservoir/aquifer problems. In general when looking at aquifer flow, there are two convenient inner boundary conditions that can be considered; constant pressure or constant flow rate. There are three outer boundary conditions that are convenient to consider; infinite, closed and constant pressure. And there are three geometries that can be solved reasonably easily; linear, radial and spherical. Thus there are a total of eighteen different solutions that can be analyzed.

  11. Post waterflood CO2 miscible flood in light oil fluvial - dominated deltaic reservoirs. Technical progress report, October 1, 1994--December 30, 1994. 1st Quarter, fiscal year 1995

    SciTech Connect (OSTI)

    1994-01-15

    Production is averaging about 450 BOPD for the quarter. The fluctuation was primarily due to a temporary shutdown of CO{sub 2} delivery and maturing of the first WAG cycle. CO{sub 2} and water injection were reversed again in order to optimize changing yields and water cuts in the producing wells. Measured BHP was close to the anticipated value. A limited CO{sub 2} volume of 120 MMCF was injected to stimulate well Kuhn No. 6 to test the Huff-Puff process, since the well did not respond to CO{sub 2} injection from the main reservoir. The well will be placed on February 1, 1995. Total CO{sub 2} injection averaged this quarter about 8.8 MMCFD, including 3.6 MMCFD purchased CO{sub 2} from Cardox. The stratigraphy of the sand deposits is also discussed.

  12. Reviving Abandoned Reservoirs with High-Pressure Air Injection: Application in a Fractured and Karsted Dolomite Reservoir

    SciTech Connect (OSTI)

    Robert Loucks; Stephen C. Ruppel; Dembla Dhiraj; Julia Gale; Jon Holder; Jeff Kane; Jon Olson; John A. Jackson; Katherine G. Jackson

    2006-09-30

    Despite declining production rates, existing reservoirs in the United States contain vast volumes of remaining oil that is not being effectively recovered. This oil resource constitutes a huge target for the development and application of modern, cost-effective technologies for producing oil. Chief among the barriers to the recovery of this oil are the high costs of designing and implementing conventional advanced recovery technologies in these mature, in many cases pressure-depleted, reservoirs. An additional, increasingly significant barrier is the lack of vital technical expertise necessary for the application of these technologies. This lack of expertise is especially notable among the small operators and independents that operate many of these mature, yet oil-rich, reservoirs. We addressed these barriers to more effective oil recovery by developing, testing, applying, and documenting an innovative technology that can be used by even the smallest operator to significantly increase the flow of oil from mature U.S. reservoirs. The Bureau of Economic Geology and Goldrus Producing Company assembled a multidisciplinary team of geoscientists and engineers to evaluate the applicability of high-pressure air injection (HPAI) in revitalizing a nearly abandoned carbonate reservoir in the Permian Basin of West Texas. The Permian Basin, the largest oil-bearing basin in North America, contains more than 70 billion barrels of remaining oil in place and is an ideal venue to validate this technology. We have demonstrated the potential of HPAI for oil-recovery improvement in preliminary laboratory tests and a reservoir pilot project. To more completely test the technology, this project emphasized detailed characterization of reservoir properties, which were integrated to access the effectiveness and economics of HPAI. The characterization phase of the project utilized geoscientists and petroleum engineers from the Bureau of Economic Geology and the Department of Petroleum Engineering (both at The University of Texas at Austin) to define the controls on fluid flow in the reservoir as a basis for developing a reservoir model. The successful development of HPAI technology has tremendous potential for increasing the flow of oil from deep carbonate reservoirs in the Permian Basin, a target resource that can be conservatively estimated at more than 1.5 billion barrels. Successful implementation in the field chosen for demonstration, for example, could result in the recovery of more than 34 million barrels of oil that will not otherwise be produced. Geological and petrophysical analysis of available data at Barnhart field reveals the following important observations: (1) the Barnhart Ellenburger reservoir is similar to most other Ellenburger reservoirs in terms of depositional facies, diagenesis, and petrophysical attributes; (2) the reservoir is characterized by low to moderate matrix porosity much like most other Ellenburger reservoirs in the Permian Basin; (3) karst processes (cave formation, infill, and collapse) have substantially altered stratigraphic architecture and reservoir properties; (4) porosity and permeability increase with depth and may be associated with the degree of karst-related diagenesis; (5) tectonic fractures overprint the reservoir, improving overall connectivity; (6) oil-saturation profiles show that the oil-water contact (OWC) is as much as 125 ft lower than previous estimations; (7) production history and trends suggest that this reservoir is very similar to other solution-gas-drive reservoirs in the Permian Basin; and (8) reservoir simulation study showed that the Barnhart reservoir is a good candidate for HPAI and that application of horizontal-well technology can improve ultimate resource recovery from the reservoir.

  13. Innovative MIOR Process Utilizing Indigenous Reservoir Constituents

    SciTech Connect (OSTI)

    Hitzman, D.O.; Stepp, A.K.

    2003-02-11

    This research program was directed at improving the knowledge of reservoir ecology and developing practical microbial solutions for improving oil production. The goal was to identify indigenous microbial populations which can produce beneficial metabolic products and develop a methodology to stimulate those select microbes with inorganic nutrient amendments to increase oil recovery. This microbial technology has the capability of producing multiple oil-releasing agents. The potential of the system will be illustrated and demonstrated by the example of biopolymer production on oil recovery.

  14. Use of Cutting-Edge Horizontal and Underbalanced Drilling Technologies and Subsurface Seismic Techniques to Explore, Drill and Produce Reservoired Oil and Gas from the Fractured Monterey Below 10,000 ft in the Santa Maria Basin of California

    SciTech Connect (OSTI)

    George Witter; Robert Knoll; William Rehm; Thomas Williams

    2005-09-29

    This project was undertaken to demonstrate that oil and gas can be drilled and produced safely and economically from a fractured Monterey reservoir in the Santa Maria Basin of California by employing horizontal wellbores and underbalanced drilling technologies. Two vertical wells were previously drilled in this area with heavy mud and conventional completions; neither was commercially productive. A new well was drilled by the project team in 2004 with the objective of accessing an extended length of oil-bearing, high-resistivity Monterey shale via a horizontal wellbore, while implementing managed-pressure drilling (MPD) techniques to avoid formation damage. Initial project meetings were conducted in October 2003. The team confirmed that the demonstration well would be completed open-hole to minimize productivity impairment. Following an overview of the geologic setting and local field experience, critical aspects of the application were identified. At the pre-spud meeting in January 2004, the final well design was confirmed and the well programming/service company requirements assigned. Various design elements were reduced in scope due to significant budgetary constraints. Major alterations to the original plan included: (1) a VSP seismic survey was delayed to a later phase; (2) a new (larger) surface hole would be drilled rather than re-enter an existing well; (3) a 7-in. liner would be placed into the top of the Monterey target as quickly as possible to avoid problems with hole stability; (4) evaluation activities were reduced in scope; (5) geosteering observations for fracture access would be deduced from penetration rate, cuttings description and hydrocarbon in-flow; and (6) rather than use nitrogen, a novel air-injection MPD system was to be implemented. Drilling operations, delayed from the original schedule by capital constraints and lack of rig availability, were conducted from September 12 to November 11, 2004. The vertical and upper curved sections were drilled and lined through the problematic shale member without major stability problems. The top of the targeted Monterey was thought to be seen at the expected TVD of 10,000 ft where the 7-in. liner was set at a 60{sup o} hole angle. Significant oil and gas shows suggested the fractured interval anticipated at the heel location had been penetrated. A total of 2572 ft of 6 1/8-in. near-horizontal interval was placed in the shale section, extending planned well length by approximately 470 ft. Very little hydrocarbon in-flow was observed from fractures along the productive interval. This may be a result of the well trajectory falling underneath the Monterey fractured zone. Hydrocarbon observations, cuttings analysis and gamma-ray response indicated additional fractured intervals were accessed along the last {+-}900 ft of well length. The well was completed with a 2 7/8-in. tubing string set in a production packer in preparation for flow and swab tests to be conducted later by a service rig. The planned well time was estimated as 39 days and overall cost as $2.4 million. The actual results are 66 days at a total cost of $3.4 million. Well productivity responses during subsequent flow and swabbing tests were negative. The well failed to inflow and only minor amounts (a few barrels) of light oil were recovered. The lack of production may suggest that actual sustainable reservoir pressure is far less than anticipated. Temblor is currently planning to re-enter and clean out the well and run an Array Induction log (primarily for resistivity and correlation purposes), and an FMI log (for fracture detection). Depending on the results of these logs, an acidizing or re-drill program will be planned.

  15. Use of Cutting-Edge Horizontal and Underbalanced Drilling Technologies and Subsurface Seismic Techniques to Explore, Drill and Produce Reservoired Oil and Gas from the Fractured Monterey Below 10,000 ft in the Santa Maria Basin of California

    SciTech Connect (OSTI)

    George Witter; Robert Knoll; William Rehm; Thomas Williams

    2006-06-30

    This project was undertaken to demonstrate that oil and gas can be drilled and produced safely and economically from a fractured Monterey reservoir in the Santa Maria Basin of California by employing horizontal wellbores and underbalanced drilling technologies. Two vertical wells were previously drilled in this area with heavy mud and conventional completions; neither was commercially productive. A new well was drilled by the project team in 2004 with the objective of accessing an extended length of oil-bearing, high-resistivity Monterey shale via a horizontal wellbore, while implementing managed-pressure drilling (MPD) techniques to avoid formation damage. Initial project meetings were conducted in October 2003. The team confirmed that the demonstration well would be completed open-hole to minimize productivity impairment. Following an overview of the geologic setting and local field experience, critical aspects of the application were identified. At the pre-spud meeting in January 2004, the final well design was confirmed and the well programming/service company requirements assigned. Various design elements were reduced in scope due to significant budgetary constraints. Major alterations to the original plan included: (1) a VSP seismic survey was delayed to a later phase; (2) a new (larger) surface hole would be drilled rather than re-enter an existing well; (3) a 7-in. liner would be placed into the top of the Monterey target as quickly as possible to avoid problems with hole stability; (4) evaluation activities were reduced in scope; (5) geosteering observations for fracture access would be deduced from penetration rate, cuttings description and hydrocarbon in-flow; and (6) rather than use nitrogen, a novel air-injection MPD system was to be implemented. Drilling operations, delayed from the original schedule by capital constraints and lack of rig availability, were conducted from September 12 to November 11, 2004. The vertical and upper curved sections were drilled and lined through the problematic shale member without major stability problems. The top of the targeted Monterey was thought to be seen at the expected TVD of 10,000 ft where the 7-in. liner was set at a 60{sup o} hole angle. Significant oil and gas shows suggested the fractured interval anticipated at the heel location had been penetrated. A total of 2572 ft of 6{Delta}-in. near-horizontal interval was placed in the shale section, extending planned well length by approximately 470 ft. Very little hydrocarbon in-flow was observed from fractures along the productive interval. This may be a result of the well trajectory falling underneath the Monterey fractured zone. Hydrocarbon observations, cuttings analysis and gamma-ray response indicated additional fractured intervals were accessed along the last {+-}900 ft of well length. The well was completed with a 2 and 7/8-in. tubing string set in a production packer in preparation for flow and swab tests to be conducted later by a service rig. The planned well time was estimated as 39 days and overall cost as $2.4 million. The actual results are 66 days at a total cost of $3.4 million. Well productivity responses during subsequent flow and swabbing tests were negative. The well failed to inflow and only minor amounts (a few barrels) of light oil were recovered. The lack of production may suggest that actual sustainable reservoir pressure is far less than anticipated. Temblor attempted in July, 2006, to re-enter and clean out the well and run an Array Induction log (primarily for resistivity and correlation purposes), and an FMI log (for fracture detection). Application of surfactant in the length of the horizontal hole, and acid over the fracture zone at 10,236 was also planned. This attempt was not successful in that the clean out tools became stuck and had to be abandoned.

  16. USE OF CUTTING-EDGE HORIZONTAL AND UNDERBALANCED DRILLING TECHNOLOGIES AND SUBSURFACE SEISMIC TECHNIQUES TO EXPLORE, DRILL AND PRODUCE RESERVOIRED OIL AND GAS FROM THE FRACTURED MONTEREY BELOW 10,000 FT IN THE SANTA MARIA BASIN OF CALIFORNIA

    SciTech Connect (OSTI)

    George Witter; Robert Knoll; William Rehm; Thomas Williams

    2005-02-01

    This project was undertaken to demonstrate that oil and gas can be drilled and produced safely and economically from a fractured Monterey reservoir in the Santa Maria Basin of California by employing horizontal wellbores and underbalanced drilling technologies. Two vertical wells were previously drilled in this area by Temblor Petroleum with heavy mud and conventional completions; neither was commercially productive. A new well was drilled by the project team in 2004 with the objective of accessing an extended length of oil-bearing, high-resistivity Monterey shale via a horizontal wellbore, while implementing managed-pressure drilling (MPD) techniques to avoid formation damage. Initial project meetings were conducted in October 2003. The team confirmed that the demonstration well would be completed open-hole to minimize productivity impairment. Following an overview of the geologic setting and local field experience, critical aspects of the application were identified. At the pre-spud meeting in January 2004, the final well design was confirmed and the well programming/service company requirements assigned. Various design elements were reduced in scope due to significant budgetary constraints. Major alterations to the original plan included: (1) a VSP seismic survey was delayed to a later phase; (2) a new (larger) surface hole would be drilled rather than re-enter an existing well; (3) a 7-in. liner would be placed into the top of the Monterey target as quickly as possible to avoid problems with hole stability; (4) evaluation activities were reduced in scope; (5) geosteering observations for fracture access would be deduced from penetration rate, cuttings description and hydrocarbon in-flow; and (6) rather than use nitrogen, a novel air-injection MPD system was to be implemented. Drilling operations, delayed from the original schedule by capital constraints and lack of rig availability, were conducted from September 12 to November 11, 2004. The vertical and upper curved sections were drilled and lined through the problematic shale member without major stability problems. The top of the targeted Monterey was thought to be seen at the expected TVD of 10,000 ft where the 7-in. liner was set at a 60{sup o} hole angle. Significant oil and gas shows suggested the fractured interval anticipated at the heel location had been penetrated. A total of 2572 ft of 6.-in. near-horizontal interval was placed in the shale section, extending planned well length by approximately 470 ft. Very little hydrocarbon in-flow was observed from fractures along the productive interval. This may be a result of the well trajectory falling underneath the Monterey fractured zone. Hydrocarbon observations, cuttings analysis and gamma-ray response indicated additional fractured intervals were accessed along the last {+-}900 ft of well length. The well was completed with a 2 7/8-in. tubing string set in a production packer in preparation for flow and swab tests to be conducted later by a service rig. The planned well time was estimated as 39 days and overall cost as $2.4 million. The actual results are 66 days at a total cost of $3.4 million. Well productivity responses during subsequent flow and swabbing tests were negative. The well failed to inflow and only minor amounts (a few barrels) of light oil were recovered. The lack of production may suggest that actual sustainable reservoir pressure is far less than anticipated. Temblor is currently investigating the costs and operational viability of re-entering the well and conducting an FMI (fracture detection) log and/or an acid stimulation. No final decision or detailed plans have been made regarding these potential interventions at this time.

  17. ALKALINE-SURFACTANT-POLYMER FLOODING AND RESERVOIR CHARACTERIZATION OF THE BRIDGEPORT AND CYPRESS RESERVOIRS OF THE LAWRENCE FIELD

    SciTech Connect (OSTI)

    Malcolm Pitts; Ron Damm; Bev Seyler

    2003-04-01

    Feasibility of alkaline-surfactant-polymer flood for the Lawrence Field in Lawrence County, Illinois is being studied. Two injected formulations are being designed; one for the Bridgeport A and Bridgeport B reservoirs and one for Cypress and Paint Creek reservoirs. Fluid-fluid and coreflood evaluations have developed a chemical solution that produces incremental oil in the laboratory from the Cypress and Paint Creek reservoirs. A chemical formulation for the Bridgeport A and Bridgeport B reservoirs is being developed. A reservoir characterization study is being done on the Bridgeport A, B, & D sandstones, and on the Cypress sandstone. The study covers the pilot flood area and the Lawrence Field.

  18. ALKALINE-SURFACTANT-POLYMER FLOODING AND RESERVOIR CHARACTERIZATION OF THE BRIDGEPORT AND CYPRESS RESERVOIRS OF THE LAWRENCE FIELD

    SciTech Connect (OSTI)

    Malcolm Pitts; Ron Damm; Bev Seyler

    2003-03-01

    Feasibility of alkaline-surfactant-polymer flood for the Lawrence Field in Lawrence County, Illinois is being studied. Two injected formulations are being designed; one for the Bridgeport A and Bridgeport B reservoirs and one for Cypress and Paint Creek reservoirs. Fluid-fluid and coreflood evaluations have developed a chemical solution that produces incremental oil in the laboratory from the Cypress and Paint Creek reservoirs. A chemical formulation for the Bridgeport A and Bridgeport B reservoirs is being developed. A reservoir characterization study is being done on the Bridgeport A, B, & D sandstones, and on the Cypress sandstone. The study covers the pilot flood area and the Lawrence Field.

  19. Chickamauga reservoir embayment study - 1990

    SciTech Connect (OSTI)

    Meinert, D.L.; Butkus, S.R.; McDonough, T.A.

    1992-12-01

    The objectives of this report are three-fold: (1) assess physical, chemical, and biological conditions in the major embayments of Chickamauga Reservoir; (2) compare water quality and biological conditions of embayments with main river locations; and (3) identify any water quality concerns in the study embayments that may warrant further investigation and/or management actions. Embayments are important areas of reservoirs to be considered when assessments are made to support water quality management plans. In general, embayments, because of their smaller size (water surface areas usually less than 1000 acres), shallower morphometry (average depth usually less than 10 feet), and longer detention times (frequently a month or more), exhibit more extreme responses to pollutant loadings and changes in land use than the main river region of the reservoir. Consequently, embayments are often at greater risk of water quality impairments (e.g. nutrient enrichment, filling and siltation, excessive growths of aquatic plants, algal blooms, low dissolved oxygen concentrations, bacteriological contamination, etc.). Much of the secondary beneficial use of reservoirs occurs in embayments (viz. marinas, recreation areas, parks and beaches, residential development, etc.). Typically embayments comprise less than 20 percent of the surface area of a reservoir, but they often receive 50 percent or more of the water-oriented recreational use of the reservoir. This intensive recreational use creates a potential for adverse use impacts if poor water quality and aquatic conditions exist in an embayment.

  20. INNOVATIVE MIOR PROCESS UTILIZING INDIGENOUS RESERVOIR CONSTITUENTS

    SciTech Connect (OSTI)

    D.O. Hitzman; A.K. Stepp; D.M. Dennis; L.R. Graumann

    2003-09-01

    This research program was directed at improving the knowledge of reservoir ecology and developing practical microbial solutions and technologies for improving oil production. The goal was to identify and utilize indigenous microbial populations which can produce beneficial metabolic products and develop a methodology to stimulate those select microbes with nutrient amendments to increase oil recovery. This microbial technology has the capability of producing multiple oil-releasing agents. Experimental laboratory work in model sandpack cores was conducted using microbial cultures isolated from produced water samples. Comparative laboratory studies demonstrating in situ production of microbial products as oil recovery agents were conducted in sand packs with natural field waters using cultures and conditions representative of oil reservoirs. Increased oil recovery in multiple model sandpack systems was achieved and the technology and results were verified by successful field studies. Direct application of the research results has lead to the development of a feasible, practical, successful, and cost-effective technology which increases oil recovery. This technology is now being commercialized and applied in numerous field projects to increase oil recovery. Two field applications of the developed technology reported production increases of 21% and 24% in oil recovery.

  1. Method for enhanced oil recovery

    DOE Patents [OSTI]

    Comberiati, Joseph R.; Locke, Charles D.; Kamath, Krishna I.

    1980-01-01

    The present invention is directed to an improved method for enhanced recovery of oil from relatively "cold" reservoirs by carbon dioxide flooding. In oil reservoirs at a temperature less than the critical temperature of 87.7.degree. F. and at a pore pressure greater than the saturation pressure of carbon dioxide at the temperature of the reservoir, the carbon dioxide remains in the liquid state which does not satisfactorily mix with the oil. However, applicants have found that carbon dioxide can be vaporized in situ in the reservoir by selectively reducing the pore pressure in the reservoir to a value less than the particular saturated vapor pressure so as to greatly enhance the mixing of the carbon dioxide with the oil.

  2. Structural Oil Pan With Integrated Oil Filtration And Cooling System

    DOE Patents [OSTI]

    Freese, V, Charles Edwin

    2000-05-09

    An oil pan for an internal combustion engine includes a body defining a reservoir for collecting engine coolant. The reservoir has a bottom and side walls extending upwardly from the bottom to present a flanged lip through which the oil pan may be mounted to the engine. An oil cooler assembly is housed within the body of the oil pan for cooling lubricant received from the engine. The body includes an oil inlet passage formed integrally therewith for receiving lubricant from the engine and delivering lubricant to the oil cooler. In addition, the body also includes an oil pick up passage formed integrally therewith for providing fluid communication between the reservoir and the engine through the flanged lip.

  3. Advanced Reservoir Characterization in the Antelope Shale to Establish the Viability of CO{sub 2} Enhanced Oil Recovery in California's Monterey Formation Siliceous Shales

    SciTech Connect (OSTI)

    Michael F. Morea

    1997-03-14

    The Buena Vista Hills field is located about 25 miles southwest of Bakersfield, in Kern County, California, about two miles north of the city of Taft, and five miles south of the Elk Hills field. The Antelope Shale zone was discovered at the Buena Vista Hills field in 1952, and has since been under primary production. Little research was done to improve the completion techniques during the development phase in the 1950s, so most of the wells are completed with about 1000 ft of slotted liner. The proposed pilot consists of four existing producers on 20 acre spacing with a new 10 acre infill well drilled as the pilot CO{sub 2} injector. Most of the reservoir characterization of the first phase of the project will be performed using data collected in the pilot pattern wells. This is the first annual report of the project. It covers the period February 12, 1996 to February 11, 1997. During this period the Chevron Murvale 653Z-26B well was drilled in Section 26-T31S/R23E in the Buena Vista Hills field, Kern County, California. The Monterey Formation equivalent Brown and Antelope Shales were continuously cored, the zone was logged with several different kinds of wireline logs, and the well was cased to a total depth of 4907 ft. Core recovery was 99.5%. Core analyses that have been performed include Dean Stark porosity, permeability and fluid saturations, field wettability, anelastic strain recovery, spectral core gamma, profile permeametry, and photographic imaging. Wireline log analysis includes mineral-based error minimization (ELAN), NMR T2 processing, and dipole shear wave anisotropy. A shear wave vertical seismic profile was acquired after casing was set and processing is nearly complete.

  4. Heavy oil and tar sands recovery and upgrading. International technology

    SciTech Connect (OSTI)

    Schumacher, M.M.

    1982-01-01

    This work provides an in-depth assessment of international technology for the recovery and upgrading of heavy crude oil and tar sands. The technologies included are currently in use, under development, or planned; emphasis is placed on post-1978 activities. The heavy oil technologies and processes considered include methods relating to the exploitation of heavy oil reservoirs, such as production from underground workings, all types of improved or enhanced recovery, subsurface extraction, and well rate stimulation. The tar sands section includes sizing the resource base and reviewing and evaluating past, present, and planned research and field developments on processes for mining, producing, extracting, and upgrading very heavy oils recovered from tar sands, e.g., bitumen recovery from tar sands where primary production was impossible because of the oil's high viscosity. 616 references.

  5. An evaluation of known remaining oil resources in the United States. Appendix, Project on Advanced Oil Recovery and the States

    SciTech Connect (OSTI)

    Not Available

    1994-10-01

    This volume contains appendices for the following: Overview of improved oil recovery methods (enhanced oil recovery methods and advanced secondary recovery methods); Benefits of improved oil recovery, selected data for the analyzed states; and List of TORIS fields and reservoirs.

  6. Reservoir facies architecture of microtidal barrier systems

    SciTech Connect (OSTI)

    Galloway, W.E.

    1986-06-01

    Sandstone reservoirs deposited in microtidal barrier systems contain large oil and gas reserves in several Gulf Coast basin plays. Three representative Frio Sandstone reservoirs in West Ranch field show that barrier-island sand bodies are complex mosaics of barrier-core, inlet-fill, flood-tidal-delta, washover-fan, barrier-flat, and shoreface facies. The proportions of these facies differ within progradational, aggradational, and transgressive barrier sand bodies. The 41-A reservoir is a progradational barrier sand body. The most important producing facies include the barrier core and crosscutting inlet fill. Permeability and distributions of irreducible water saturation reveal depositional patterns and subdivisions of the sand body into numerous facies-controlled compartments. Both original hydrocarbon saturation and irregularities in water encroachment show that the facies compartments locally affect fluid movement within the reservoir. The Greta reservoir is an aggradational barrier complex. This massive sand body consists of intermixed barrier-core and inlet-fill units. Prominent resistivity compartments are dip oriented, indicating the importance of inlet development during barrier aggradation. Despite the uniform appearance of the Greta reservoir, water encroachment has been irregular. The Glasscock reservoir is characterized by comparatively low permeability and is an atypically thin and discontinuous Frio reservoir. It is interpreted to be a transgressive barrier deposit that consists mainly of large washover-fan and associated barrier-flat sands. Hydrocarbon saturation, drainage, and injection response all reflect the facies geometry typical of a transgressive barrier complex.

  7. Discrete Feature Approach for Heterogeneous Reservoir Production Enhancement

    SciTech Connect (OSTI)

    Dershowitz, William S.; Curran, Brendan; Einstein, Herbert; LaPointe, Paul; Shuttle, Dawn; Klise, Kate

    2002-07-26

    The report presents summaries of technology development for discrete feature modeling in support of the improved oil recovery (IOR) for heterogeneous reservoirs. In addition, the report describes the demonstration of these technologies at project study sites.

  8. Feasibility study of heavy oil recovery in the Appalachian, Black Warrior, Illinois, and Michigan basins

    SciTech Connect (OSTI)

    Olsen, D.K.; Rawn-Schatzinger, V.; Ramzel, E.B.

    1992-07-01

    This report is one of a series of publications assessing the feasibility of increasing domestic heavy oil production. Each report covers select areas of the United States. The Appalachian, Black Warrior, Illinois, and Michigan basins cover most of the depositional basins in the Midwest and Eastern United States. These basins produce sweet, paraffinic light oil and are considered minor heavy oil (10{degrees} to 20{degrees} API gravity or 100 to 100,000 cP viscosity) producers. Heavy oil occurs in both carbonate and sandstone reservoirs of Paleozoic Age along the perimeters of the basins in the same sediments where light oil occurs. The oil is heavy because escape of light ends, water washing of the oil, and biodegradation of the oil have occurred over million of years. The Appalachian, Black Warrior, Illinois, and Michigan basins' heavy oil fields have produced some 450,000 bbl of heavy oil of an estimated 14,000,000 bbl originally in place. The basins have been long-term, major light-oil-producing areas and are served by an extensive pipeline network connected to refineries designed to process light sweet and with few exceptions limited volumes of sour or heavy crude oils. Since the light oil is principally paraffinic, it commands a higher price than the asphaltic heavy crude oils of California. The heavy oil that is refined in the Midwest and Eastern US is imported and refined at select refineries. Imports of crude of all grades accounts for 37 to >95% of the oil refined in these areas. Because of the nature of the resource, the Appalachian, Black Warrior, Illinois and Michigan basins are not expected to become major heavy oil producing areas. The crude oil collection system will continue to degrade as light oil production declines. The demand for crude oil will increase pipeline and tanker transport of imported crude to select large refineries to meet the areas' liquid fuels needs.

  9. Feasibility study of heavy oil recovery in the Appalachian, Black Warrior, Illinois, and Michigan basins

    SciTech Connect (OSTI)

    Olsen, D.K.; Rawn-Schatzinger, V.; Ramzel, E.B.

    1992-07-01

    This report is one of a series of publications assessing the feasibility of increasing domestic heavy oil production. Each report covers select areas of the United States. The Appalachian, Black Warrior, Illinois, and Michigan basins cover most of the depositional basins in the Midwest and Eastern United States. These basins produce sweet, paraffinic light oil and are considered minor heavy oil (10{degrees} to 20{degrees} API gravity or 100 to 100,000 cP viscosity) producers. Heavy oil occurs in both carbonate and sandstone reservoirs of Paleozoic Age along the perimeters of the basins in the same sediments where light oil occurs. The oil is heavy because escape of light ends, water washing of the oil, and biodegradation of the oil have occurred over million of years. The Appalachian, Black Warrior, Illinois, and Michigan basins` heavy oil fields have produced some 450,000 bbl of heavy oil of an estimated 14,000,000 bbl originally in place. The basins have been long-term, major light-oil-producing areas and are served by an extensive pipeline network connected to refineries designed to process light sweet and with few exceptions limited volumes of sour or heavy crude oils. Since the light oil is principally paraffinic, it commands a higher price than the asphaltic heavy crude oils of California. The heavy oil that is refined in the Midwest and Eastern US is imported and refined at select refineries. Imports of crude of all grades accounts for 37 to >95% of the oil refined in these areas. Because of the nature of the resource, the Appalachian, Black Warrior, Illinois and Michigan basins are not expected to become major heavy oil producing areas. The crude oil collection system will continue to degrade as light oil production declines. The demand for crude oil will increase pipeline and tanker transport of imported crude to select large refineries to meet the areas` liquid fuels needs.

  10. Waterflood surveillance techniques; A reservoir management approach

    SciTech Connect (OSTI)

    Thakur, G.C. )

    1991-10-01

    The reservoir management aspects of waterflooding span the time before the start of waterflood to the time when the secondary recovery either is uneconomic or is changed to an enhanced recovery. This paper reviews waterflood techniques and reports on surveillance techniques in the management of waterflooding of oil wells.

  11. Faulted reservoirs characterization by an image processing technique

    SciTech Connect (OSTI)

    Martinez-Angeles, R.

    1994-12-31

    This paper has developed an image processing method for obtaining the discontinuous areal distribution of oil parameters (formation top, porosity, water saturation,...) of faulted heterogeneous oil reservoirs. For its application it requires the previous knowledge of a set of discrete values z(k,l) from well-logs and seismic profiles. Faulted structures were discretized into continuous structures or blocks bounded by faults. The theoretical fundamental assumption of the proposed method establishes that the natural distributions can be considered as the superposition of several elementary brownian distributions, represented by discrete values z(k,l), whose physical model is the diffusion differential equation and its solution associated. This is a technique that allows the representation of a composed brownian distribution as a linear combination of all elementary brownian functions. For illustrating the operational aspect of brownian analysis, two examples are studied. The results are presented as a digital images by means of an image processing software. This method can be applied in mapping, three dimensions interpolation and reserves calculation of faulted reservoirs.

  12. Status of Norris Reservoir

    SciTech Connect (OSTI)

    Not Available

    1990-09-01

    This is one in a series of reports prepared by the Tennessee Valley Authority (TVA) for those interested in the conditions of TVA reservoirs. This overview of Norris Reservoir summarizes reservoir and watershed characteristics, reservoir uses, conditions that impair reservoir uses, water quality and aquatic biological conditions, and activities of reservoir management agencies. This information was extracted from the most up-to-date publications and data available, and from interviews with water resource professionals in various federal, state, and local agencies, and in public and private water supply and wastewater treatment facilities. 14 refs., 3 figs.

  13. Feasibility study of heavy oil recovery in the Permian Basin (Texas and New Mexico)

    SciTech Connect (OSTI)

    Olsen, D.K.; Johnson, W.I.

    1993-05-01

    This report is one of a series of publications assessing the feasibility of increasing domestic heavy oil production. Each report covers select areas of the United States. The Permian Basin of West Texas and Southeastern New Mexico is made up of the Midland, Delaware, Val Verde, and Kerr Basins; the Northwestern, Eastern, and Southern shelves; the Central Basin Platform, and the Sheffield Channel. The present day Permian Basin was one sedimentary basin until uplift and subsidence occurred during Pennsylvanian and early Permian Age to create the configuration of the basins, shelves, and platform of today. The basin has been a major light oil producing area served by an extensive pipeline network connected to refineries designed to process light sweet and limited sour crude oil. Limited resources of heavy oil (10`` to 20`` API gravity) occurs in both carbonate and sandstone reservoirs of Permian and Cretaceous Age. The largest cumulative heavy oil production comes from fluvial sandstones of the Cretaceous Trinity Group. Permian heavy oil is principally paraffinic and thus commands a higher price than asphaltic California heavy oil. Heavy oil in deeper reservoirs has solution gas and low viscosity and thus can be produced by primary and by waterflooding. Because of the nature of the resource, the Permian Basin should not be considered a major heavy oil producing area.

  14. Feasibility study of heavy oil recovery in the Permian Basin (Texas and New Mexico)

    SciTech Connect (OSTI)

    Olsen, D.K.; Johnson, W.I.

    1993-05-01

    This report is one of a series of publications assessing the feasibility of increasing domestic heavy oil production. Each report covers select areas of the United States. The Permian Basin of West Texas and Southeastern New Mexico is made up of the Midland, Delaware, Val Verde, and Kerr Basins; the Northwestern, Eastern, and Southern shelves; the Central Basin Platform, and the Sheffield Channel. The present day Permian Basin was one sedimentary basin until uplift and subsidence occurred during Pennsylvanian and early Permian Age to create the configuration of the basins, shelves, and platform of today. The basin has been a major light oil producing area served by an extensive pipeline network connected to refineries designed to process light sweet and limited sour crude oil. Limited resources of heavy oil (10'' to 20'' API gravity) occurs in both carbonate and sandstone reservoirs of Permian and Cretaceous Age. The largest cumulative heavy oil production comes from fluvial sandstones of the Cretaceous Trinity Group. Permian heavy oil is principally paraffinic and thus commands a higher price than asphaltic California heavy oil. Heavy oil in deeper reservoirs has solution gas and low viscosity and thus can be produced by primary and by waterflooding. Because of the nature of the resource, the Permian Basin should not be considered a major heavy oil producing area.

  15. Enhanced Oil Recovery | Department of Energy

    Office of Energy Efficiency and Renewable Energy (EERE) Indexed Site

    Enhanced Oil Recovery Enhanced Oil Recovery Cross-section illustrating how carbon dioxide and water can be used to flush residual oil from a subsurface rock formation between wells. Cross-section illustrating how carbon dioxide and water can be used to flush residual oil from a subsurface rock formation between wells. Crude oil development and production in U.S. oil reservoirs can include up to three distinct phases: primary, secondary, and tertiary (or enhanced) recovery. During primary

  16. Process for tertiary oil recovery using tall oil pitch

    DOE Patents [OSTI]

    Radke, C.J.

    1983-07-25

    A process and compositions for enhancing the recovery of acid crudes are disclosed. The process involves injecting caustic solutions into the reservoir to maintain a pH of 11 to 13. The fluid contains an effective amount of multivalent cation for inhibiting alkaline silica dissolution with the reservoir. A tall oil pitch soap is added as a polymeric mobility control agent. (DMC)

  17. Status of Cherokee Reservoir

    SciTech Connect (OSTI)

    Not Available

    1990-08-01

    This is the first in a series of reports prepared by Tennessee Valley Authority (TVA) for those interested in the conditions of TVA reservoirs. This overviews of Cherokee Reservoir summarizes reservoir and watershed characteristics, reservoir uses and use impairments, water quality and aquatic biological conditions, and activities of reservoir management agencies. This information was extracted from the most current reports, publications, and data available, and interviews with water resource professionals in various Federal, state, and local agencies and in public and private water supply and wastewater treatment facilities. 11 refs., 4 figs., 1 tab.

  18. Status of Wheeler Reservoir

    SciTech Connect (OSTI)

    Not Available

    1990-09-01

    This is one in a series of status reports prepared by the Tennessee Valley Authority (TVA) for those interested in the conditions of TVA reservoirs. This overview of Wheeler Reservoir summarizes reservoir purposes and operation, reservoir and watershed characteristics, reservoir uses and use impairments, and water quality and aquatic biological conditions. The information presented here is from the most recent reports, publications, and original data available. If no recent data were available, historical data were summarized. If data were completely lacking, environmental professionals with special knowledge of the resource were interviewed. 12 refs., 2 figs.

  19. EXPLOITATION AND OPTIMIZATION OF RESERVOIR PERFORMANCE IN HUNTON FORMATION, OKLAHOMA

    SciTech Connect (OSTI)

    Mohan Kelkar

    2003-10-01

    This report presents the work done so far on Hunton Formation in West Carney Field in Lincoln County, Oklahoma. West Carney Field produces oil and gas from the Hunton Formation. The field was developed starting in 1995. Some of the unique characteristics of the field include decreasing water oil ratio over time, decreasing gas-oil ratio at the beginning of production, inability to calculate oil reserves in the field based on log data, and sustained oil rates over long periods of time. To understand the unique characteristics of the field, an integrated evaluation was undertaken. Production data from the field were meticulously collected, and over forty wells were cored and logged to better understand the petrophysical and engineering characteristics. Based on the work done in this budget period so far, some of the preliminary conclusions can be listed as follows: (1) Based on PVT analysis, the field most likely contains volatile oil with bubble point close to initial reservoir pressure of 1,900 psia. (2) The initial oil in place, which is contact with existing wells, can be determined by newly developed material balance technique. The oil in place, which is in communication, is significantly less than determined by volumetric analysis, indicating heterogeneous nature of the reservoir. The oil in place, determined by material balance, is greater than determined by decline curve analysis. This difference may lead to additional locations for in fill wells. (3) The core and log evaluation indicates that the intermediate pores (porosity between 2 and 6 %) are very important in determining production potential of the reservoir. These intermediate size pores contain high oil saturation. (4) The limestone part of the reservoir, although low in porosity (mostly less than 6 %) is much more prolific in terms of oil production than the dolomite portion of the reservoir. The reason for this difference is the higher oil saturation in low porosity region. As the average porosity increases, the remaining oil saturation decreases. This is evident from log and core analysis. (5) Using a compositional simulator, we are able to reproduce the important reservoir characteristics by assuming a two layer model. One layer is high permeability region containing water and the other layer is low permeability region containing mostly oil. The results are further verified by using a dual porosity model. Assuming that most of the volatile oil is contained in the matrix and the water is contained in the fractures, we are able to reproduce important reservoir performance characteristics. (6) Evaluation of secondary mechanisms indicates that CO{sub 2} flooding is potentially a viable option if CO{sub 2} is available at reasonable price. We have conducted detailed simulation studies to verify the effectiveness of CO{sub 2} huff-n-puff process. We are in the process of conducting additional lab tests to verify the efficacy of the same displacement. (7) Another possibility of improving the oil recovery is to inject surfactants to change the near well bore wettability of the rock from oil wet to water wet. By changing the wettability, we may be able to retard the water flow and hence improve the oil recovery as a percentage of total fluid produced. If surfactant is reasonably priced, other possibility is also to use huff-n-puff process using surfactants. Laboratory experiments are promising, and additional investigation continues. (8) Preliminary economic evaluation indicates that vertical wells outperform horizontal wells. Future work in the project would include: (1) Build multi-well numerical model to reproduce overall reservoir performance rather than individual well performance. Special emphasis will be placed on hydrodynamic connectivity between wells. (2) Collect data from adjacent Hunton reservoirs to validate our understanding of what makes it a productive reservoir. (3) Develop statistical methods to rank various reservoirs in Hunton formation. This will allow us to evaluate other Hunton formations based on old well logs, and determine, apriori, if

  20. Oil Production

    Energy Science and Technology Software Center (OSTI)

    1989-07-01

    A horizontal and slanted well model was developed and incorporated into BOAST, a black oil simulator, to predict the potential production rates for such wells. The HORIZONTAL/SLANTED WELL MODEL can be used to calculate the productivity index, based on the length and location of the wellbore within the block, for each reservoir grid block penetrated by the horizontal/slanted wellbore. The well model can be run under either pressure or rate constraints in which wellbore pressuresmore » can be calculated as an option of infinite-conductivity. The model can simulate the performance of multiple horizontal/slanted wells in any geometric combination within reservoirs.« less

  1. EXPLOITATION AND OPTIMIZATION OF RESERVOIR PERFORMANCE IN HUNTON FORMATION, OKLAHOMA

    SciTech Connect (OSTI)

    Mohan Kelkar

    2002-03-31

    The West Carney Field in Lincoln County, Oklahoma is one of few newly discovered oil fields in Oklahoma. Although profitable, the field exhibits several unusual characteristics. These include decreasing water-oil ratios, decreasing gas-oil ratios, decreasing bottomhole pressures during shut-ins in some wells, and transient behavior for water production in many wells. This report explains the unusual characteristics of West Carney Field based on detailed geological and engineering analyses. We propose a geological history that explains the presence of mobile water and oil in the reservoir. The combination of matrix and fractures in the reservoir explains the reservoir's flow behavior. We confirm our hypothesis by matching observed performance with a simulated model and develop procedures for correlating core data to log data so that the analysis can be extended to other, similar fields where the core coverage may be limited.

  2. Development of a 400 Level 3C Clamped Downhole Seismic Receiver Array for 3D Borehole Seismic Imaging of Gas Reservoirs

    SciTech Connect (OSTI)

    Bjorn N. P. Paulsson

    2006-09-30

    Borehole seismology is the highest resolution geophysical imaging technique available today to the oil and gas industry for characterization and monitoring of oil and gas reservoirs. However, the industry's ability to perform high resolution 3D imaging of deep and complex gas reservoirs using borehole seismology has been hampered by the lack of acquisition technology necessary to record large volumes of high frequency, high signal-to-noise-ratio borehole seismic data. This project took aim at this shortcoming by developing a 400 level 3C clamped downhole seismic receiver array, and accompanying software, for borehole seismic 3D imaging. This large borehole seismic array has removed the technical acquisition barrier for recording the data volumes necessary to do high resolution 3D VSP and 3D cross-well seismic imaging. Massive 3D VSP{reg_sign} and long range Cross-Well Seismology (CWS) are two of the borehole seismic techniques that promise to take the gas industry to the next level in their quest for higher resolution images of deep and complex oil and gas reservoirs. Today only a fraction of the oil or gas in place is produced when reservoirs are considered depleted. This is primarily due to our lack of understanding of detailed compartmentalization of oil and gas reservoirs. In this project, we developed a 400 level 3C borehole seismic receiver array that allows for economic use of 3D borehole seismic imaging for reservoir characterization and monitoring. This new array has significantly increased the efficiency of recording large data volumes at sufficiently dense spatial sampling to resolve reservoir complexities. The receiver pods have been fabricated and tested to withstand high temperature (200 C/400 F) and high pressure (25,000 psi), so that they can operate in wells up to 7,620 meters (25,000 feet) deep. The receiver array is deployed on standard production or drill tubing. In combination with 3C surface seismic or 3C borehole seismic sources, the 400 level receiver array can be used to obtain 3D 9C data. These 9C borehole seismic data provide both compressional wave and shear wave information that can be used for quantitative prediction of rock and pore fluid types. The 400-level borehole receiver array has been deployed successfully in a number of oil and gas wells during the course of this project, and each survey has resulted in marked improvements in imaging of geologic features that are critical for oil or gas production but were previously considered to be below the limits of seismic resolution. This added level of reservoir detail has resulted in improved well placement in the oil and gas fields that have been drilled using the Massive 3D VSP{reg_sign} images. In the future, the 400-level downhole seismic receiver array is expected to continue to improve reservoir characterization and drilling success in deep and complex oil and gas reservoirs.

  3. Reactivation of an Idle Lease to Increase Heavy Oil Recovery through Application of Conventional Steam Drive Technology in a Low-Dip Slope and Reservoir in the Midway-Sunset Field, San Jaoquin Basin, California, Class III

    SciTech Connect (OSTI)

    Schamel, S.

    2001-01-09

    The objective of this project is not just to produce oil from the Pru Fee property, but rather to test which operational strategies best optimize total oil recovery at economically acceptable rates of production and production costs.

  4. Reactivation of an Idle Lease to Increase Heavy Oil Recovery through Application of Conventional Steam Drive Technology in a Low-Dip Slope and Reservoir in the Midway-Sunset Field, San Jaoquin Basin, California, Class III

    SciTech Connect (OSTI)

    Schamel, Steven; Deo, Milind; Deets, Mike

    2002-02-21

    The objective of the project is not just to commercially produce oil from the Pru Fee property, but rather to test which operational strategies best optimize total oil recovery at economically acceptable rates of production volumes and costs.

  5. Enhanced oil recovery using flash-driven steamflooding

    DOE Patents [OSTI]

    Roark, Steven D.

    1990-01-01

    The present invention is directed to a novel steamflooding process which utilizes three specific stages of steam injection for enhanced oil recovery. The three stages are as follows: As steam is being injected into an oil-bearing reservoir through an injection well, the production rate of a production well located at a distance from the injection well is gradually restricted to a point that the pressure in the reservoir increases at a predetermined rate to a predetermined maximum value. After the maximum pressure has been reached, the production rate is increased to a value such that the predetermined maximum pressure value is maintained. Production at maximum pressure is continued for a length of time that will be unique for each individual reservoir. In some cases, this step of the steamflooding process of the invention may be omitted entirely. In the third stage of the steamflooding process of the invention, production rates at the producing well are increased gradually to allow the pressure to decrease down from the maximum pressure value to the original pressure value at the producing well. The rate of pressure reduction will be unique for each reservoir. After completing stage three, the three stages can be repeated or the steamflood may be terminated as considered desirable.

  6. Blackfoot Reservoir Geothermal Area | Open Energy Information

    Open Energy Info (EERE)

    Resource Estimate Mean Reservoir Temp: Estimated Reservoir Volume: Mean Capacity: USGS Mean Reservoir Temp: USGS Estimated Reservoir Volume: USGS Mean Capacity: Click "Edit With...

  7. Blackfoot Reservoir Geothermal Area | Open Energy Information

    Open Energy Info (EERE)

    GEA Development Phase: Resource Estimate Mean Reservoir Temp: Estimated Reservoir Volume: Mean Capacity: USGS Mean Reservoir Temp: USGS Estimated Reservoir Volume: USGS Mean...

  8. Improved characterization of reservoir behavior by integration of reservoir performances data and rock type distributions

    SciTech Connect (OSTI)

    Davies, D.K.; Vessell, R.K.; Doublet, L.E.

    1997-08-01

    An integrated geological/petrophysical and reservoir engineering study was performed for a large, mature waterflood project (>250 wells, {approximately}80% water cut) at the North Robertson (Clear Fork) Unit, Gaines County, Texas. The primary goal of the study was to develop an integrated reservoir description for {open_quotes}targeted{close_quotes} (economic) 10-acre (4-hectare) infill drilling and future recovery operations in a low permeability, carbonate (dolomite) reservoir. Integration of the results from geological/petrophysical studies and reservoir performance analyses provide a rapid and effective method for developing a comprehensive reservoir description. This reservoir description can be used for reservoir flow simulation, performance prediction, infill targeting, waterflood management, and for optimizing well developments (patterns, completions, and stimulations). The following analyses were performed as part of this study: (1) Geological/petrophysical analyses: (core and well log data) - {open_quotes}Rock typing{close_quotes} based on qualitative and quantitative visualization of pore-scale features. Reservoir layering based on {open_quotes}rock typing {close_quotes} and hydraulic flow units. Development of a {open_quotes}core-log{close_quotes} model to estimate permeability using porosity and other properties derived from well logs. The core-log model is based on {open_quotes}rock types.{close_quotes} (2) Engineering analyses: (production and injection history, well tests) Material balance decline type curve analyses to estimate total reservoir volume, formation flow characteristics (flow capacity, skin factor, and fracture half-length), and indications of well/boundary interference. Estimated ultimate recovery analyses to yield movable oil (or injectable water) volumes, as well as indications of well and boundary interference.

  9. APPLICATION OF RESERVOIR CHARACTERIZATION AND ADVANCED TECHNOLOGY TO IMPROVE RECOVERY AND ECONOMICS IN A LOWER QUALITY SHALLOW SHELF SAN ANDRES RESERVOIR

    SciTech Connect (OSTI)

    T. Scott Hickman; James J. Justice

    2001-06-16

    The Class 2 Project at West Welch was designed to demonstrate the use of advanced technologies to enhance the economics of improved oil recovery (IOR) projects in lower quality Shallow Shelf Carbonate (SSC) reservoirs, resulting in recovery of additional oil that would otherwise be left in the reservoir at project abandonment. Accurate reservoir description is critical to the effective evaluation and efficient design of IOR projects in the heterogeneous SSC reservoirs. Therefore, the majority of Budget Period 1 was devoted to reservoir characterization. Technologies being demonstrated include: (1) Advanced petrophysics; (2) Three-dimensional (3-D) seismic; (3) Crosswell bore tomography; (4) Advanced reservoir simulation; (5) Carbon dioxide (CO{sub 2}) stimulation treatments; (6) Hydraulic fracturing design and monitoring; and (7) Mobility control agents.

  10. APPLICATION OF RESERVOIR CHARACTERIZATION AND ADVANCED TECHNOLOGY TO IMPROVE RECOVERY AND ECONOMICS IN A LOWER QUALITY SHALLOW SHELF SAN ANDRES RESERVOIR

    SciTech Connect (OSTI)

    T. Scott Hickman; James J. Justice

    2001-12-11

    The Class 2 Project at West Welch was designed to demonstrate the use of advanced technologies to enhance the economics of improved oil recovery (IOR) projects in lower quality Shallow Shelf Carbonate (SSC) reservoirs, resulting in recovery of additional oil that would otherwise be left in the reservoir at project abandonment. Accurate reservoir description is critical to the effective evaluation and efficient design of IOR projects in the heterogeneous SSC reservoirs. Therefore, the majority of Budget Period 1 was devoted to reservoir characterization. Technologies being demonstrated include: (1) Advanced petrophysics; (2) Three-dimensional (3-D) seismic; (3) Crosswell bore tomography; (4) Advanced reservoir simulation; (5) Carbon dioxide (CO{sub 2}) stimulation treatments; (6) Hydraulic fracturing design and monitoring; and (7) Mobility control agents.

  11. APPLICATION OF RESERVOIR CHARACTERIZATION AND ADVANCED TECHNOLOGY TO IMPROVE RECOVERY AND ECONOMICS IN A LOWER QUALITY SHALLOW SHELF SAN ANDRES RESERVOIR

    SciTech Connect (OSTI)

    T. Scott Hickman

    2003-01-17

    The Class 2 Project at West Welch was designed to demonstrate the use of advanced technologies to enhance the economics of improved oil recovery (IOR) projects in lower quality Shallow Shelf Carbonate (SSC) reservoirs, resulting in recovery of additional oil that would otherwise be left in the reservoir at project abandonment. Accurate reservoir description is critical to the effective evaluation and efficient design of IOR projects in the heterogeneous SSC reservoirs. Therefore, the majority of Budget Period 1 was devoted to reservoir characterization. Technologies being demonstrated include: (1) Advanced petrophysics; (2) Three-dimensional (3-D) seismic; (3) Crosswell bore tomography; (4) Advanced reservoir simulation; (5) Carbon dioxide (CO{sub 2}) stimulation treatments; (6) Hydraulic fracturing design and monitoring; and (7) Mobility control agents.

  12. Reactivation of an Idle Lease to Increase Heavy Oil Recovery through Application of Conventional Steam Drive Technology in a Low Dip Slope and Basin Reservoir in the Midway-Sunset Field, San Jaoquin Basin, California, Class III

    SciTech Connect (OSTI)

    Schamel, Steven; Deo, Milind; Deets, Mike; Olsen, Keven

    2000-04-20

    During the initial phase of the project a multifaceted feasibility study was carried out to examine whether the pilot project could be justified technically and economically at this site. This study included: (1) Recompletion of 9 shut-in wells and drilling of a additional producer and a new temperature observation well. A core was taken from the reservoir interval in the new producer, Pru-101. The wells were produced by conventional cyclic steaming over a period of 15 months to establish a production baseline for the site, (2) Characterization of the stratigraphy and petrophysical properties of the Monarch Sand reservoir using existing well logs and analyses on samples in the core taken from Pru-101. The resulting data were used to develop a geostatistical model of the reservoir at the Pru Fee property and a specific reservoir simulator for the pilot test site on the property, and (3) Use of the reservoir simulator to test various steamflood and cyclic steaming production options leading to design of a production strategy for the pilot steamflood based on a four pattern, 9-spot array covering 8 ac near the center of the 40 ac Pru Fee property. The array chosen required drilling additional producers and injectors to supplement the existing wells recompleted in the initial phase of the project.

  13. High resolution reservoir geological modelling using outcrop information

    SciTech Connect (OSTI)

    Zhang Changmin; Lin Kexiang; Liu Huaibo

    1997-08-01

    This is China`s first case study of high resolution reservoir geological modelling using outcrop information. The key of the modelling process is to build a prototype model and using the model as a geological knowledge bank. Outcrop information used in geological modelling including seven aspects: (1) Determining the reservoir framework pattern by sedimentary depositional system and facies analysis; (2) Horizontal correlation based on the lower and higher stand duration of the paleo-lake level; (3) Determining the model`s direction based on the paleocurrent statistics; (4) Estimating the sandbody communication by photomosaic and profiles; (6) Estimating reservoir properties distribution within sandbody by lithofacies analysis; and (7) Building the reservoir model in sandbody scale by architectural element analysis and 3-D sampling. A high resolution reservoir geological model of Youshashan oil field has been built by using this method.

  14. Sixth workshop on geothermal reservoir engineering: Proceedings

    SciTech Connect (OSTI)

    Ramey, H.J. Jr.; Kruger, P.

    1980-12-18

    INTRODUCTION TO THE PROCEEDINGS OF THE SIXTH GEOTHERMAL RESERVOIR ENGINEERING WORKSHOP, STANFORD GEOTHERMAL PROGRAM Henry J. Ramey, Jr., and Paul Kruger Co-Principal Investigators Ian G. Donaldson Program Manager Stanford Geothermal Program The Sixth Workshop on Geothermal Reservoir Engineering convened at Stanford University on December 16, 1980. As with previous Workshops the attendance was around 100 with a significant participation from countries other than the United States (18 attendees from 6 countries). In addition, there were a number of papers from foreign contributors not able to attend. Because of the success of all the earlier workshops there was only one format change, a new scheduling of Tuesday to Thursday rather than the earlier Wednesday through Friday. This change was in general considered for the better and will be retained for the Seventh Workshop. Papers were presented on two and a half of the three days, the panel session, this year on the numerical modeling intercomparison study sponsored by the Department of Energy, being held on the second afternoon. This panel discussion is described in a separate Stanford Geothermal Program Report (SGP-TR42). This year there was a shift in subject of the papers. There was a reduction in the number of papers offered on pressure transients and well testing and an introduction of several new subjects. After overviews by Bob Gray of the Department of Energy and Jack Howard of Lawrence Berkeley Laboratory, we had papers on field development, geopressured systems, production engineering, well testing, modeling, reservoir physics, reservoir chemistry, and risk analysis. A total of 51 papers were contributed and are printed in these Proceedings. It was, however, necessary to restrict the presentations and not all papers printed were presented. Although the content of the Workshop has changed over the years, the format to date has proved to be satisfactory. The objectives of the Workshop, the bringing together of researchers, engineers and managers involved in geothermal reservoir study and development and the provision of a forum for the prompt and open reporting of progress and for the exchange of ideas, continue to be met . Active discussion by the majority of the participants is apparent both in and outside the workshop arena. The Workshop Proceedings now contain some of the most highly cited geothermal literature. Unfortunately, the popularity of the Workshop for the presentation and exchange of ideas does have some less welcome side effects. The major one is the developing necessity for a limitation of the number of papers that are actually presented. We will continue to include all offered papers in the Summaries and Proceedings. As in the recent past, this sixth Workshop was supported by a grant from the Department of Energy. This grant is now made directly to Stanford as part of the support for the Stanford Geothermal Program (Contract No. DE-AT03-80SF11459). We are certain that all participants join us in our appreciation of this continuing support. Thanks are also due to all those individuals who helped in so many ways: The members of the program committee who had to work so hard to keep the program to a manageable size - George Frye (Aminoil USA), Paul G. Atkinson (Union Oil Company). Michael L. Sorey (U.S.G.S.), Frank G. Miller (Stanford Geothermal Program), and Roland N. Horne (Stanford Geothermal Program). The session chairmen who contributed so much to the organization and operation of the technical sessions - George Frye (Aminoil USA), Phillip H. Messer (Union Oil Company), Leland L. Mink (Department of Energy), Manuel Nathenson (U.S.G.S.), Gunnar Bodvarsson (Oregon State University), Mohindar S. Gulati (Union Oil Company), George F. Pinder (Princeton University), Paul A. Witherspoon (Lawrence Berkeley Laboratory), Frank G. Miller (Stanford Geothermal Program) and Michael J. O'Sullivan (Lawrence Berkeley Laboratory). The many people who assisted behind the scenes, making sure that everything was prepared and organized - in particular we would like to thank Jean Cook and Joanne Hartford (Petroleum Engineering Department, Stanford University) without whom there may never have been a Sixth Workshop. Henry J. Ramey, Jr. Paul Kruger Ian G. Donaldson Stanford University December 31, 1980

  15. Geological and production characteristics of strandplain/barrier island reservoirs in the United States

    SciTech Connect (OSTI)

    Cole, E.L.; Fowler, M.; Jackson, S.; Madden, M.P.; Reeves, T.K.; Salamy, S.P.; Young, M.A.

    1994-12-01

    The Department of Energy`s (DOE`s) primary mission in the oil research program is to maximize the economically and environmentally sound recovery of oil from domestic reservoirs and to preserve access to this resource. The Oil Recovery Field Demonstration Program supports DOE`s mission through cost-shared demonstrations of improved Oil Recovery (IOR) processes and reservoir characterization methods. In the past 3 years, the DOE has issued Program Opportunity Notices (PONs) seeking cost-shared proposals for the three highest priority, geologically defined reservoir classes. The classes have been prioritized based on resource size and risk of abandonment. This document defines the geologic, reservoir, and production characteristics of the fourth reservoir class, strandplain/barrier islands. Knowledge of the geological factors and processes that control formation and preservation of reservoir deposits, external and internal reservoir heterogeneities, reservoir characterization methodology, and IOR process application can be used to increase production of the remaining oil-in-place (IOR) in Class 4 reservoirs. Knowledge of heterogeneities that inhibit or block fluid flow is particularly critical. Using the TORIS database of 330 of the largest strandplain/barrier island reservoirs and its predictive and economic models, the recovery potential which could result from future application of IOR technologies to Class 4 reservoirs was estimated to be between 1.0 and 4.3 billion barrels, depending on oil price and the level of technology advancement. The analysis indicated that this potential could be realized through (1) infill drilling alone and in combination with polymer flooding and profile modification, (2) chemical flooding (sufactant), and (3) thermal processes. Most of this future potential is in Texas, Oklahoma, and the Rocky Mountain region. Approximately two-thirds of the potentially recoverable resource is at risk of abandonment by the year 2000.

  16. Reservoir Temperature Estimator

    Energy Science and Technology Software Center (OSTI)

    2014-12-08

    The Reservoir Temperature Estimator (RTEst) is a program that can be used to estimate deep geothermal reservoir temperature and chemical parameters such as CO2 fugacity based on the water chemistry of shallower, cooler reservoir fluids. This code uses the plugin features provided in The Geochemist’s Workbench (Bethke and Yeakel, 2011) and interfaces with the model-independent parameter estimation code Pest (Doherty, 2005) to provide for optimization of the estimated parameters based on the minimization of themore » weighted sum of squares of a set of saturation indexes from a user-provided mineral assemblage.« less

  17. EXPLOITATION AND OPTIMIZATION OF RESERVOIR PERFORMANCE IN HUNTON FORMATION, OKLAHOMA

    SciTech Connect (OSTI)

    Mohan Kelkar

    2005-02-01

    Hunton formation in Oklahoma has displayed some unique production characteristics. These include high initial water-oil and gas-oil ratios, decline in those ratios over time and temporary increase in gas-oil ratio during pressure build up. The formation also displays highly complex geology, but surprising hydrodynamic continuity. This report addresses three key issues related specifically to West Carney Hunton field and, in general, to any other Hunton formation exhibiting similar behavior: (1) What is the primary mechanism by which oil and gas is produced from the field? (2) How can the knowledge gained from studying the existing fields can be extended to other fields which have the potential to produce? (3) What can be done to improve the performance of this reservoir? We have developed a comprehensive model to explain the behavior of the reservoir. By using available production, geological, core and log data, we are able to develop a reservoir model which explains the production behavior in the reservoir. Using easily available information, such as log data, we have established the parameters needed for a field to be economically successful. We provide guidelines in terms of what to look for in a new field and how to develop it. Finally, through laboratory experiments, we show that surfactants can be used to improve the hydrocarbons recovery from the field. In addition, injection of CO{sub 2} or natural gas also will help us recover additional oil from the field.

  18. Salinity, temperature, oil composition, and oil recovery by waterflooding

    SciTech Connect (OSTI)

    Tang, G.Q.; Morrow, N.R.

    1997-11-01

    The effect of aging and displacement temperatures and brine and oil composition on wettability and the recovery of crude oil by spontaneous imbibition and waterflooding has been investigated. This study is based on displacement tests in Berea sandstone with three crude oils and three reservoir brines (RB`s). Salinity was varied by changing the concentration of total dissolved solids (TDS`s) of the synthetic brine in proportion. Salinity of the connate and invading brines can have a major influence on wettability and oil recovery at reservoir temperature. Oil recovery increased over that for the RB with dilution of both the initial (connate) and invading brine or dilution of either. Aging and displacement temperatures were varied independently. For all crude oils, water wetness and oil recovery increased with increase in displacement temperature. Removal of light components from the crude oil resulted in increased water wetness. Addition of alkanes to the crude oil reduced the water wetness, and increased oil recovery. Relationships between waterflood recovery and rate and extent of oil recovery by spontaneous imbibition are summarized.

  19. Crude Oil Analysis Database

    DOE Data Explorer [Office of Scientific and Technical Information (OSTI)]

    Shay, Johanna Y.

    The composition and physical properties of crude oil vary widely from one reservoir to another within an oil field, as well as from one field or region to another. Although all oils consist of hydrocarbons and their derivatives, the proportions of various types of compounds differ greatly. This makes some oils more suitable than others for specific refining processes and uses. To take advantage of this diversity, one needs access to information in a large database of crude oil analyses. The Crude Oil Analysis Database (COADB) currently satisfies this need by offering 9,056 crude oil analyses. Of these, 8,500 are United States domestic oils. The database contains results of analysis of the general properties and chemical composition, as well as the field, formation, and geographic location of the crude oil sample. [Taken from the Introduction to COAMDATA_DESC.pdf, part of the zipped software and database file at http://www.netl.doe.gov/technologies/oil-gas/Software/database.html] Save the zipped file to your PC. When opened, it will contain PDF documents and a large Excel spreadsheet. It will also contain the database in Microsoft Access 2002.

  20. An innovative secondary recovery approach for a marginal reservoir

    SciTech Connect (OSTI)

    Clark, T.J.; Hanafy, H.H.

    1995-11-01

    The Younis Lower Rudeis reservoir is operated by the Gulf of Suez Petroleum Company (GUPCO) in a remote area of the Gulf of Suez, Egypt. Before concluding that Younis had no future potential, GUPCO commissioned a reservoir/facility engineering team to study the reservoir development potential. First, reservoir simulation would be used to improve the understanding of the depletion mechanism and the original oil in place. Second, simulation would be used to determine the potential for waterflooding. Third, if waterflooding potential exists,the team must find a way to economically develop the incremental reserves. The reservoir simulation work clarified the depletion mechanism in Younis, and indicated a significant potential for waterflooding exists. History matching of the historical reservoir performance discovered that a much larger reservoir volume is actually present than mapped, and that ultimate recovery will actually reach only 22 percent of the OOIP. Furthermore, while gravity segregation of gas is occurring, significant unrecovered oil reserves will remain downdip of the current producers. Waterflooding could aid recovery of this downdip oil. With expected reserves from the waterflood project to total 5.3 MMBO, the facility engineers were challenged with providing up to 6000 BPD of water to the platform. An innovative technique was ultimately designed to install all needed equipment on the Younis unmanned platform for a remote waterflood. Since surface injection is expected to occur under a vacuum due to the low reservoir pressure, inexpensive equipment would be used to withdraw water from the Gulf, treat and filter, and deliver to the injection well at the required rate.

  1. Seismicity and Reservoir Fracture Characterization

    Broader source: Energy.gov [DOE]

    Below are the project presentations and respective peer review results for Seismicity and Reservoir Fracture Characterization.

  2. Reservoir Modeling Working Group Meeting

    Broader source: Energy.gov [DOE]

    Reservoir Modeling working group meeting presentation on May 10, 2012 at the 2012 Peer Review Meeting.

  3. Characterization of dynamic change of Fan-delta reservoir properties in water-drive development

    SciTech Connect (OSTI)

    Wu Shenghe; Xiong Qihua; Liu Yuhong

    1997-08-01

    Fan-delta reservoir in Huzhuangji oil field of east China, is a typical highly heterogeneous reservoir. The oil field has been developed by water-drive for 10 years, but the oil recovery is less than 12%, and water cut is over 90%, resulting from high heterogeneity and serious dynamic change of reservoir properties. This paper aims at the study of dynamic change of reservoir properties in water-drive development. Through quantitative imaging analysis and mercury injection analysis of cores from inspection wells, the dynamic change of reservoir pore structure in water-drive development was studied. The results show that the {open_quotes}large pore channels{close_quotes} develop in distributary channel sandstone and become larger in water-drive development, resulting in more serious pore heterogeneity. Through reservoir sensitivity experiments, the rock-fluid reaction in water-drive development is studied. The results show the permeability of some distal bar sandstone and deserted channel sandstone becomes lower due to swelling of I/S clay minerals in pore throats. OD the other hand, the permeability of distributary channel and mouth bar sandstone become larger because the authigenic Koalinites in pore throats are flushed away with the increase of flow rate of injection water. Well-logging analysis of flooded reservoirs are used to study the dynamic change of reservoir properties in various flow units. The distribution of remaining oil is closely related to the types and distribution of flow units.

  4. REVIVING ABANDONED RESERVOIRS WITH HIGH-PRESSURE AIR INJECTION: APPLICATION IN A FRACTURED AND KARSTED DOLOMITE RESERVOIR

    SciTech Connect (OSTI)

    Robert Loucks; Steve Ruppel; Julia Gale; Jon Holder; Jon Olsen; Deanna Combs; Dhiraj Dembla; Leonel Gomez

    2003-06-01

    The Bureau of Economic Geology and Goldrus Producing Company have assembled a multidisciplinary team of geoscientists and engineers to evaluate the applicability of high-pressure air injection (HPAI) in revitalizing a nearly abandoned carbonate reservoir in the Permian Basin of West Texas. The characterization phase of the project is utilizing geoscientists and petroleum engineers from the bureau of Economic Geology and the Department of Petroleum Engineering (both at The University of Texas at Austin) to define the controls on fluid flow in the reservoir as a basis for developing a reservoir model. This model will be used to define a field deployment plant that Goldrus, a small independent oil company, will implement by drilling both vertical and horizontal wells during the demonstration phase of the project. Additional reservoir data are being gathered during the demonstration phase to improve the accuracy of the reservoir model. The results of the demonstration are being closely monitored to provide a basis for improving the design of the HPAI field deployment plan. The results of the reservoir characterization field demonstration and monitoring program will be documented and widely disseminated to facilitate adoption of this technology by oil operators in the Permian Basin and elsewhere in the US.

  5. Implications of outcrop geology for reservoirs in the Neogene productive series: Apsheron peninsula, Azerbaijan

    SciTech Connect (OSTI)

    Reynolds, A.D.; Bowman, M.B.J.; Henton, J.

    1998-01-01

    The Neogene sediments of eastern Azerbaijan and western Turkmenistan contain significant hydrocarbon reserves in deltaic reservoirs. Sedimentary logging of these reservoirs at outcrop in Azerbaijan has outlined four facies associations that encompass a range of paleoenvironments, from alluvial braided river sandstones and conglomerates to delta-front siltstones and mudstones. The facies associations suggest a river-dominated braid delta and are arranged into an architecture controlled by base-level changes: parasequences, parasequence sets, and sequence boundaries are key elements. The facies associations and stratigraphic architecture, together with outcrop observations of cementation and faulting, are summarized in terms of four idealized reservoir models: fluvial, delta plain, proximal delta front, and distal delta front. Each reservoir model has distinctive grain-size and shale distributions. Comparison of nearby oil fields with the studied outcrops suggests that the outcrops form good analogs from which to model reservoir architecture, barriers and baffles to fluid flow, reservoir heterogeneity, and reservoir quality variations.

  6. SOVENT BASED ENHANCED OIL RECOVERY FOR IN-SITU UPGRADING OF HEAVY OIL SANDS

    SciTech Connect (OSTI)

    Munroe, Norman

    2009-01-30

    With the depletion of conventional crude oil reserves in the world, heavy oil and bitumen resources have great potential to meet the future demand for petroleum products. However, oil recovery from heavy oil and bitumen reservoirs is much more difficult than that from conventional oil reservoirs. This is mainly because heavy oil or bitumen is partially or completely immobile under reservoir conditions due to its extremely high viscosity, which creates special production challenges. In order to overcome these challenges significant efforts were devoted by Applied Research Center (ARC) at Florida International University and The Center for Energy Economics (CEE) at the University of Texas. A simplified model was developed to assess the density of the upgraded crude depending on the ratio of solvent mass to crude oil mass, temperature, pressure and the properties of the crude oil. The simplified model incorporated the interaction dynamics into a homogeneous, porous heavy oil reservoir to simulate the dispersion and concentration of injected CO2. The model also incorporated the characteristic of a highly varying CO2 density near the critical point. Since the major challenge in heavy oil recovery is its high viscosity, most researchers have focused their investigations on this parameter in the laboratory as well as in the field resulting in disparaging results. This was attributed to oil being a complex poly-disperse blend of light and heavy paraffins, aromatics, resins and asphaltenes, which have diverse behaviors at reservoir temperature and pressures. The situation is exacerbated by a dearth of experimental data on gas diffusion coefficients in heavy oils due to the tedious nature of diffusivity measurements. Ultimately, the viscosity and thus oil recovery is regulated by pressure and its effect on the diffusion coefficient and oil swelling factors. The generation of a new phase within the crude and the differences in mobility between the new crude matrix and the precipitate readily enables removal of asphaltenes. Thus, an upgraded crude low in heavy metal, sulfur and nitrogen is more conducive for further purification.

  7. Geothermal Reservoir Well Stimulation Program: technology transfer

    SciTech Connect (OSTI)

    Not Available

    1980-05-01

    A literature search on reservoir and/or well stimulation techniques suitable for application in geothermal fields is presented. The literature on stimulation techniques in oil and gas field applications was also searched and evaluated as to its relevancy to geothermal operations. The equivalent low-temperature work documented in the open literature is cited, and an attempt is made to evaluate the relevance of this information as far as high-temperature stimulation work is concerned. Clays play an important role in any stimulation work. Therefore, special emphasis has been placed on clay behavior anticipated in geothermal operations. (MHR)

  8. Putting integrated reservoir characterization into practice - in house training

    SciTech Connect (OSTI)

    Wright, F.M. Jr.; Best, D.A.; Clarke, R.T.

    1997-08-01

    The need for even more efficient reservoir characterization and management has forced a change in the way Mobil Oil provides technical support to its production operations. We`ve learned that to be successful, a good understanding of the reservoir is essential. This includes an understanding of the technical and business significance of reservoir heterogeneities at different stages of field development. A multi-disciplinary understanding of the business of integrated reservoir characterization is essential and to facilitate this understanding, Mobil has developed a highly successful {open_quotes}Reservoir Characterization Field Seminar{close_quotes}. Through specific team based case studies that incorporate outcrop examples and data the program provides participants the opportunity to explore historic and alternative approaches to reservoir description, characterization and management. We explore appropriate levels and timing of data gathering, technology applications, risk assessment and management practices at different stages of field development. The case studies presented throughout the course are a unique element of the program which combine real life and hypothetical problem sets that explore how different technical disciplines interact, the approaches to a problem solving they use, the assumptions and uncertainties contained in their contributions and the impact those conclusions may have on other disciplines involved in the overall reservoir management process. The team building aspect of the course was an added bonus.

  9. Bridging the Gap between Chemical Flooding and Independent Oil Producers

    SciTech Connect (OSTI)

    Stan McCool; Tony Walton; Paul Whillhite; Mark Ballard; Miguel Rondon; Kaixu Song; Zhijun Liu; Shahab Ahmed; Peter Senior

    2012-03-31

    Ten Kanas oil reservoirs/leases were studied through geological and engineering analysis to assess the potential performance of chemical flooding to recover oil. Reservoirs/leases that have been efficiently waterflooded have the highest performance potential for chemical flooding. Laboratory work to identify efficient chemical systems and to test the oil recovery performance of the systems was the major effort of the project. Efficient chemical systems were identified for crude oils from nine of the reservoirs/leases. Oil recovery performance of the identified chemical systems in Berea sandstone rocks showed 90+ % recoveries of waterflood residual oil for seven crude oils. Oil recoveries increased with the amount of chemical injected. Recoveries were less in Indiana limestone cores. One formulation recovered 80% of the tertiary oil in the limestone rock. Geological studies for nine of the oil reservoirs are presented. Pleasant Prairie, Trembley, Vinland and Stewart Oilfields in Kansas were the most favorable of the studied reservoirs for a pilot chemical flood from geological considerations. Computer simulations of the performance of a laboratory coreflood were used to predict a field application of chemical flooding for the Trembley Oilfield. Estimates of field applications indicated chemical flooding is an economically viable technology for oil recovery.

  10. Effect of temperature, salinity and oil composition on wetting behavior and oil recovery by waterflooding

    SciTech Connect (OSTI)

    Tang, G.Q.; Morrow, N.R.

    1996-12-31

    The effect of aging and displacement temperatures, and brine and oil composition on wettability and the recovery of crude oil by spontaneous imbibition and waterflooding has been investigated. This study is based on displacement tests in Berea Sandstone using three distinctly different crude oils and three reservoir brines. Brine concentration was varied by changing the concentration of total dissolved solids of the synthetic brine in proportion to give brine of twice, one tenth, and one hundredth of the reservoir brine concentration. Aging and displacement temperatures were varied independently. For all crude oils, water-wetness and oil recovery increased with increase in displacement temperature. Tests on the effect of brine concentration showed that salinity of the connate and invading brines can have a major influence on wettability and oil recovery at reservoir temperature. Oil recovery increased over that for the reservoir brine with dilution of both the initial (connate) and invading brine or dilution of either. Removal of light components from the crude oil resulted in increased water-wetness. Addition of alkanes to the crude oil reduced the water-wetness, and increased oil recovery. Relationships between waterflood recovery and wettability are summarized.

  11. Reinjection into geothermal reservoirs

    SciTech Connect (OSTI)

    Bodvarsson, G.S.; Stefansson, V.

    1987-08-01

    Reinjection of geothermal wastewater is practiced as a means of disposal and for reservoir pressure support. Various aspects of reinjection are discussed, both in terms of theoretical studies as well as specific field examples. The discussion focuses on the major effects of reinjection, including pressure maintenance and chemical and thermal effects. (ACR)

  12. Modeling and laboratory investigations of microbial oil recovery mechanisms in porous media

    SciTech Connect (OSTI)

    Chang, M.M.; Bryant, R.S.; Stepp, A.K.; Bertus, K.M.

    1992-12-01

    Simulation and experimental results on the transport of microbes and nutrients in one-dimensional cores are presented, and the development of a three-dimensional, three-phase, multiple-component numerical model to describe the microbial transport and oil recovery in porous media is described. The change of rock`s wettability and associated relative permeability values after microbial treatments were accounted for in the model for additional oil recovery. Porosity and permeability reductions due to cell clogging have been considered and the production of gas by microbial metabolism has been incorporated. Governing equations for microbial and nutrient transport are coupled with continuity and flow equations under conditions appropriate for a black oil reservoir. The computer simulator has been used to determine the effects of various transport parameters on microbial transport phenomena. The model can accurately describe the observed transport of microbes, nutrients, and metabolites in coreflooding experiments. Input parameters are determined by matching laboratory experimental results. The model can be used to predict the propagation of microbes and nutrients in a model reservoir and to optimize injection strategies. Optimization of injection strategy results in increased oil recovery due to improvements in sweep efficiency. Field-scale numerical simulation studies using data from relative permeability experiments indicated that microbial treatment could improve oil recovery over waterflooding alone. This report addresses the work conducted under project BE3 of the FY92 annual plan.

  13. Modeling and laboratory investigations of microbial oil recovery mechanisms in porous media

    SciTech Connect (OSTI)

    Chang, M.M.; Bryant, R.S.; Stepp, A.K.; Bertus, K.M.

    1992-12-01

    Simulation and experimental results on the transport of microbes and nutrients in one-dimensional cores are presented, and the development of a three-dimensional, three-phase, multiple-component numerical model to describe the microbial transport and oil recovery in porous media is described. The change of rock's wettability and associated relative permeability values after microbial treatments were accounted for in the model for additional oil recovery. Porosity and permeability reductions due to cell clogging have been considered and the production of gas by microbial metabolism has been incorporated. Governing equations for microbial and nutrient transport are coupled with continuity and flow equations under conditions appropriate for a black oil reservoir. The computer simulator has been used to determine the effects of various transport parameters on microbial transport phenomena. The model can accurately describe the observed transport of microbes, nutrients, and metabolites in coreflooding experiments. Input parameters are determined by matching laboratory experimental results. The model can be used to predict the propagation of microbes and nutrients in a model reservoir and to optimize injection strategies. Optimization of injection strategy results in increased oil recovery due to improvements in sweep efficiency. Field-scale numerical simulation studies using data from relative permeability experiments indicated that microbial treatment could improve oil recovery over waterflooding alone. This report addresses the work conducted under project BE3 of the FY92 annual plan.

  14. Gypsy Field project in reservoir characterization

    SciTech Connect (OSTI)

    Castagna, John P.; Jr., O'Meara, Daniel J.

    2000-01-12

    The overall objective of this project was to use extensive Gypsy Field Laboratory and data as a focus for developing and testing reservoir characterization methods that are targeted at improved recovery of conventional oil. This report describes progress since project report DOE/BC/14970-7 and covers the period June 1997-September 1998 and represents one year of funding originally allocated for the year 1996. During the course of the work previously performed, high resolution geophysical and outcrop data revealed the importance of fractures at the Gypsy site. In addition, personnel changes and alternative funding (OCAST and oil company support of various kinds) allowed the authors to leverage DOE contributions and focus more on geophysical characterization.

  15. Unconventional Oil and Gas Projects Help Reduce Environmental Impact of

    Energy Savers [EERE]

    Development | Department of Energy Unconventional Oil and Gas Projects Help Reduce Environmental Impact of Development Unconventional Oil and Gas Projects Help Reduce Environmental Impact of Development April 17, 2014 - 11:30am Addthis Unconventional Oil and Gas Projects Help Reduce Environmental Impact of Development Since the first commercial oil well was drilled in the United States in 1859, most of the nation's oil and natural gas has come from reservoirs from which the resources are

  16. A field laboratory for improved oil recovery

    SciTech Connect (OSTI)

    Hildebrandt, A.F.; McDonald, J.; Claridge, E.; Killough, J.

    1992-09-01

    The purpose of Annex III of the Memorandum of Understanding, undertaken by the Houston Petroleum Research Center at the University of Houston, was to develop a field laboratory for research in improved oil recovery using a Gulf Coast reservoir in Texas. The participants: (1) make a field site selection and conducted a high resolution seismic survey in the demonstration field, (2) obtained characteristics of the reservoir (3) developed an evaluation of local flood efficiency in different parts of the demonstration reservoir, (4) used diverse methodology to evaluate the potential recovery of the remaining oil in the test reservoir, (5) developed cross-well seismic tomography, and (6) will transfer the learned technologies to oil operators through publication and workshops. This abstract is an overview of these tasks.

  17. New developments in high resolution borehole seismology and their applications to reservoir development and management

    SciTech Connect (OSTI)

    Paulsson, B.N.P.

    1997-08-01

    Single-well seismology, Reverse Vertical Seismic Profiles (VSP`s) and Crosswell seismology are three new seismic techniques that we jointly refer to as borehole seismology. Borehole seismic techniques are of great interest because they can obtain much higher resolution images of oil and gas reservoirs than what is obtainable with currently used seismic techniques. The quality of oil and gas reservoir management decisions depend on the knowledge of both the large and the fine scale features in the reservoirs. Borehole seismology is capable of mapping reservoirs with an order of magnitude improvement in resolution compared with currently used technology. In borehole seismology we use a high frequency seismic source in an oil or gas well and record the signal in the same well, in other wells, or on the surface of the earth.

  18. Maquoketa paleotopography key to reservoirs in western Illinois

    SciTech Connect (OSTI)

    Whitaker, S.T.; Ledbetter, J.C.

    1996-08-12

    Shallow Silurian reservoirs in western Illinois have been a primary target for exploration since the late 1950s. It was not until the discovery and development of Buckhorn Consolidated field in the early 1980s, however, that significant drilling efforts for Silurian reservoirs were focused on western Illinois. At Buckhorn, 1.7 million bbl of oil have been produced from a basal Silurian dolomite at about 650 ft. Drawn by inexpensive drilling and available acreage, hundreds of operators flocked to western Illinois to try their luck. By the late 1980s, however, exploration efforts in western Illinois were curtailed due to the failure to locate additional significant reservoirs. Much of this failure was due to the lack of a suitable geologic model that could be used to explain the reason for reservoir development and thereby guide exploration efforts. An article by Whitaker and Howard in 1995 presented a geologic model explaining Silurian reservoir development and stratigraphic entrapment of oil at Buckhorn Consolidated field were formed as Silurian dolomite in-filled a shallow paleovalley cut into the underlying Ordovician Maquoketa shale. Some companies have recently initiated new exploration efforts in the area using this model. This paper discusses the efforts and results of several of these new areas.

  19. Simulation studies to evaluate the effect of fracture closure on the performance of fractured reservoirs; Final report

    SciTech Connect (OSTI)

    Howrie, I.; Dauben, D.

    1994-03-01

    A three-year research program to evaluate the effect of fracture closure on the recovery of oil and gas from naturally fractured reservoirs has been completed. The overall objectives of the study were to: (1) evaluate the reservoir conditions for which fracture closure is significant, and (2) evaluate innovative fluid injection techniques capable of maintaining pressure within the reservoir. The evaluations of reservoir performance were made by a modern dual porosity simulator, TETRAD. This simulator treats both porosity and permeability as functions of pore pressure. The Austin Chalk in the Pearsall Field in of South Texas was selected as the prototype fractured reservoir for this work. During the first year, simulations of vertical and horizontal well performance were made assuming that fracture permeability was insensitive to pressure change. Sensitivity runs indicated that the simulator was predicting the effects of critical reservoir parameters in a logical and consistent manner. The results confirmed that horizontal wells could increase both rate of oil recovery and total oil recovery from naturally fractured reservoirs. In the second year, the performance of the same vertical and horizontal wells was reevaluated with fracture permeability treated as a function of reservoir pressure. To investigate sensitivity to in situ stress, differing loading conditions were assumed. Simulated natural depletions confirm that pressure sensitive fractures degrade well performance. The severity of degradation worsens when the initial reservoir pressure approaches the average stress condition of the reservoir, such as occurs in over pressured reservoirs. Simulations with water injection indicate that degradation of permeability can be counteracted when reservoir pressure is maintained and oil recovery can be increased when reservoir properties are favorable.

  20. Methodologies for Reservoir Characterization Using Fluid Inclusion...

    Office of Energy Efficiency and Renewable Energy (EERE) Indexed Site

    Methodologies for Reservoir Characterization Using Fluid Inclusion Gas Chemistry Methodologies for Reservoir Characterization Using Fluid Inclusion Gas Chemistry Methodologies for ...

  1. Oil Study Guide - Middle School | Department of Energy

    Energy Savers [EERE]

    Middle School Oil Study Guide - Middle School PDF icon Oil Study Guide - Middle School More Documents & Publications Oil Study Guide - High School evaluation_egs_tech_2008.pdf A History of Geothermal Energy Research and Development in the United States: Reservoir Engineering 1976-2006

  2. Heavy oil and tar sands recovery and upgrading: international technology

    SciTech Connect (OSTI)

    Schumacher, M.M.

    1982-01-01

    This book provides an in-depth assessment of international technology for the recovery and upgrading of heavy crude oil and tar sands. The technologies included are currently in use, under development, or planned; emphasis is placed on post-1978 activities. The heavy oil technologies and processes considered in Part I include methods relating to the exploitation of heavy oil reservoirs, such as production from undergorun workings, all types of improved or enhanced recovery, subsurface extraction, and well rate stimulation. Furthermore, even though heavy crudes are understood to include only those liquid or semiliquid hydrocarbons with a gravity of 20/sup 0/API or less, technology applied to lighter crude oils with in situ viscosities of the same order of magnitude as some US heavy oils is also included. The scope of the tar sands section (Part II) includes sizing the resource base and reviewing and evaluatin past, present, and planned research and field developments on processes for mining, producing, extracting, and upgrading very heavy oils recovered from tar sands, e.g., bitumen recovery from tar sands where primary production was impossible because of the oil's high viscosity. On the production side, very heavy oil is defined as having a gravity less than 10/sup 0/ to 12/sup 0/API and greater than 100,000-centipoise viscosity at 50/sup 0/F. On the upgrading side, hydrocarbons whose characteristics dictated additional processing prior to conventional refining into salable products (1050+/sup 0/ material) were included, regardless of origin, in order to encompass all pertinent upgrading technologies.

  3. Gas-assisted gravity drainage (GAGD) process for improved oil recovery

    DOE Patents [OSTI]

    Rao, Dandina N.

    2012-07-10

    A rapid and inexpensive process for increasing the amount of hydrocarbons (e.g., oil) produced and the rate of production from subterranean hydrocarbon-bearing reservoirs by displacing oil downwards within the oil reservoir and into an oil recovery apparatus is disclosed. The process is referred to as "gas-assisted gravity drainage" and comprises the steps of placing one or more horizontal producer wells near the bottom of a payzone (i.e., rock in which oil and gas are found in exploitable quantities) of a subterranean hydrocarbon-bearing reservoir and injecting a fluid displacer (e.g., CO.sub.2) through one or more vertical wells or horizontal wells. Pre-existing vertical wells may be used to inject the fluid displacer into the reservoir. As the fluid displacer is injected into the top portion of the reservoir, it forms a gas zone, which displaces oil and water downward towards the horizontal producer well(s).

  4. Using Chemicals to Optimize Conformance Control in Fractured Reservoirs

    SciTech Connect (OSTI)

    Seright, Randall S.; Liang, Jenn-Tai; Schrader, Richard; Hagstrom II, John; Wang, Ying; Kumar, Ananad; Wavrik, Kathryn

    2001-10-29

    This report describes work performed during the third and final year of the project, Using Chemicals to Optimize Conformance Control in Fractured Reservoirs. This research project had three objectives. The first objective was to develop a capability to predict and optimize the ability of gels to reduce permeability to water more than that to oil or gas. The second objective was to develop procedures for optimizing blocking agent placement in wells where hydraulic fractures cause channeling problems. The third objective was to develop procedures to optimize blocking agent placement in naturally fractured reservoirs.

  5. Experimental and numerical investigation of one-dimensional waterflood in porous reservoir

    SciTech Connect (OSTI)

    Hadia, N.; Chaudhari, L.; Mitra, Sushanta K.; Aggarwal, A.; Vinjamur, M.; Singh, R.

    2007-11-15

    Experimental and numerical investigation of relative permeability and oil recovery from the porous reservoir are described for short and long core samples. The relative permeability ratios, which are function of water saturation, obtained from laboratory core flooding experiments have been used for prediction of oil recovery through numerical simulation of non-dimensional Buckley-Leverett equation. The simulation results for oil recovery compared well with recovery results obtained from core flooding experiments. (author)

  6. Reservoir analysis of the Palinpinon geothermal field, Negros Oriental, Philippines

    SciTech Connect (OSTI)

    Amistoso, A.E.; Aquino, B.G.; Aunzo, Z.P.; Jordan, O.T.; Ana, F.X.M.S.; Bodvarsson, G.S.; Doughty, C.

    1993-10-01

    The Philippine National Oil Company and Lawrence Berkeley Laboratory have conducted an informal cooperative project on the reservoir evaluation of the Palinpinon geothermal field in the Philippines. The work involved the development of various numerical models of the field in order to understand the observed data. A three-dimensional porous medium model of the reservoir has been developed that matches well the observed pressure declines and enthalpy transients of the wells. Submodels representing the reservoir as a fractured porous medium were developed for the analysis of chemical transport of chlorides within the reservoir and the movement of the cold water front away from injection wells. These models indicate that the effective porosity of the reservoir varies between 1 and 7% and the effective permeability between 1 and 45 millidarcies. The numerical models were used to predict the future performance of the Palinpinon reservoir using various possible exploitation scenarios. A limited number of make-up wells were allocated to each sector of the field. When all the make-up wells had been put on line, power production gradually began to decline. The model indicates that under the assumed conditions it will not be possible to maintain the planned power production of 112.5 MWe at Palinpinon I and 80 MWe at Palinpinon II for the next 30 years, but the decline in power output will be within acceptable normal operating capacities of the plants.

  7. Reservoir heterogeneity in carboniferous sandstone of the Black Warrior basin. Final report

    SciTech Connect (OSTI)

    Kugler, R.L.; Pashin, J.C.; Carroll, R.E.; Irvin, G.D.; Moore, H.E.

    1994-06-01

    Although oil production in the Black Warrior basin of Alabama is declining, additional oil may be produced through improved recovery strategies, such as waterflooding, chemical injection, strategic well placement, and infill drilling. High-quality characterization of reservoirs in the Black Warrior basin is necessary to utilize advanced technology to recover additional oil and to avoid premature abandonment of fields. This report documents controls on the distribution and producibility of oil from heterogeneous Carboniferous reservoirs in the Black Warrior basin of Alabama. The first part of the report summarizes the structural and depositional evolution of the Black Warrior basin and establishes the geochemical characteristics of hydrocarbon source rocks and oil in the basin. This second part characterizes facies heterogeneity and petrologic and petrophysical properties of Carter and Millerella sandstone reservoirs. This is followed by a summary of oil production in the Black Warrior basin and an evaluation of seven improved-recovery projects in Alabama. In the final part, controls on the producibility of oil from sandstone reservoirs are discussed in terms of a scale-dependent heterogeneity classification.

  8. Reservoir heterogeneity in Carboniferous sandstone of the Black Warrior basin. Final report

    SciTech Connect (OSTI)

    Kugler, R.L.; Pashin, J.C.; Carroll, R.E.; Irvin, G.D.; Moore, H.E.

    1994-04-01

    Although oil production in the Black Warrior basin of Alabama is declining, additional oil may be produced through improved recovery strategies, such as waterflooding, chemical injection, strategic well placement, and infill drilling. High-quality characterization of reservoirs in the Black Warrior basin is necessary to utilize advanced technology to recover additional oil and to avoid premature abandonment of fields. This report documents controls on the distribution and producibility of oil from heterogeneous Carboniferous reservoirs in the Black Warrior basin of Alabama. The first part of the report summarizes the structural and depositional evolution of the Black Warrior basin and establishes the geochemical characteristics of hydrocarbon source rocks and oil in the basin. This second part characterizes facies heterogeneity and petrologic and petrophysical properties of Carter and Millerella sandstone reservoirs. This is followed by a summary of oil production in the Black Warrior basin and an evaluation of seven improved-recovery projects in Alabama. In the final part, controls on the producibility of oil from sandstone reservoirs are discussed in terms of a scale-dependent heterogeneity classification.

  9. Advanced Reservoir Characterization and Evaluation of C02 Gravity Drainage in the Naturally Fractured Sprayberry Trend Area

    SciTech Connect (OSTI)

    David S. Schechter

    1998-04-30

    The objective is to assess the economic feasibility of CO2 flooding of the naturally fractured Straberry Trend Area in west Texas. Research is being conducted in the extensive characterization of the reservoirs, the experimental studies of crude oil/brine/rock (COBR) interaction in the reservoirs, the analytical and numerical simulation of Spraberry reservoirs, and the experimental investigations on CO2 gravity drainage in Spraberry whole cores.

  10. The Potosi Reservoir Model 2013

    SciTech Connect (OSTI)

    Adushita, Yasmin; Smith, Valerie; Leetaru, Hannes

    2014-09-30

    As a part of a larger project co-funded by the United States Department of Energy (US DOE) to evaluate the potential of formations within the Cambro-Ordovician strata above the Mt. Simon as potential targets for carbon sequestration in the Illinois and Michigan Basins, the Illinois Clean Coal Institute (ICCI) requested Schlumberger to evaluate the potential injectivity and carbon dioxide (CO2) plume size of the Cambrian Potosi Formation. The evaluation of this formation was accomplished using wireline data, core data, pressure data, and seismic data from the US DOE-funded Illinois Basin–Decatur Project (IBDP) being conducted by the Midwest Geological Sequestration Consortium in Macon County, Illinois. In 2010, technical performance evaluations on the Cambrian Potosi Formation were performed through reservoir modeling. The data included formation tops from mud logs, well logs from the VW1 and the CCS1 wells, structural and stratigraphic formation from three dimensional (3D) seismic data, and field data from several waste water injection wells for Potosi Formation. Intention was for two million tons per annum (MTPA) of CO2 to be injected for 20 years. In the preceding, the 2010 Potosi heterogeneous model (referred to as the "Potosi Dynamic Model 2010" in this topical report) was re-run using a new injection scenario; 3.2 MTPA for 30 years. The extent of the Potosi Dynamic Model 2010, however, appeared too small for the new injection target. It was not sufficiently large enough to accommodate the evolution of the plume. The new model, Potosi Dynamic Model 2013a, was built by extending the Potosi Dynamic Model 2010 grid to 30 miles x 30 miles (48.3km x48.3km), while preserving all property modeling workflows and layering. This model was retained as the base case of Potosi Dynamic Model 2013a. The Potosi reservoir model was updated to take into account the new data from the verification well VW2 which was drilled in 2012. The new porosity and permeability modeling was performed to take into account the log data from the new well. Revisions of the 2010 modeling assumptions were also done on relative permeability, capillary pressures, formation water salinity, and the maximum allowable well bottomhole pressure. Dynamic simulations were run using the injection target of 3.2 MTPA for 30 years. This new dynamic model was named Potosi Dynamic Model 2013b. Due to the major uncertainties on the vugs permeability, two models were built; the Pessimistic and Optimistic Cases. The Optimistic Case assumes vugs permeability of 9,000 mD, which is analog to the vugs permeability identified in the pressure fall off test of a waste water injector in the Tuscola site, approx. 40 miles (64.4km) away from the IBDP area. The Pessimistic Case assumes that the vugs permeability is equal to the log data, which does not take into account the permeability from secondary porosity. The probability of such case is deemed low and could be treated as the worst case scenario, since the contribution of secondary porosity to the permeability is neglected and the loss circulation events might correspond to a much higher permeability. It is considered important, however, to identify the range of possible reservoir performance since there are no rigorous data available for the vugs permeability. The Optimistic Case gives an average CO2 injection rate of 0.8 MTPA and cumulative injection of 26 MT in 30 years, which corresponds to 27% of the injection target. The injection rate is approx. 3.2 MTPA in the first year as the well is injecting into the surrounding vugs, and declines rapidly to 0.8 MTPA in year 4 once the surrounding vugs are full and the CO2 start to reach the matrix. This implies that according to this preliminary model, a minimum of four (4) wells could be required to achieve the injection target. This result is lower than the injectivity estimated in the Potosi Dynamic Model 2013a (43 MT in 30 years), since the permeability model applied in the Potosi Dynamic Model 2013b is more conservative. This revision was deemed necessary to treat the uncertainty in a more appropriate manner. As the CO2 follows the paths where vugs interconnection exists, a reasonably large and irregular plume extent was created. For the Optimistic Case, the plume extends 17 miles (27.4km) in E-W and 14 miles (22.5km) in N-S directions after 30 years. After injection is completed, the plume continues to migrate laterally, mainly driven by the remaining pressure gradient. After 100 years post injection, the plume extends 20 miles (32.2km) in E-W and 15.5 miles (24.9km) in N-S directions. Should the targeted cumulative injection of 96 MT be achieved; a much larger plume extent could be expected. For the Optimistic Case, the increase of reservoir pressure at the end of injection is approximately 1200 psia (8,274 kPa) around the injector and gradually decreases away from the well. The reservoir pressure increase is less than 30 psia (206.8 kPa) beyond 14 miles (22.5km) away from injector. Should the targeted cumulative injection of 96 MT be achieved; a much larger areal pressure increase could be expected. The initial reservoir pressure is nearly restored after approximately 100 years post injection. The presence of matrix slows down the pressure dissipations. The Pessimistic Case gives an average CO2 injection rate of 0.2 MTPA and cumulative injection of 7 MT in 30 years, which corresponds to 7% of the injection target. This implies that in the worst case scenario, a minimum of sixteen (16) wells could be required to achieve the injection target. The present evaluation is mainly associated with uncertainty on the vugs permeability, distribution, and interconnectivity. The different results indicated by the Optimistic and Pessimistic Cases signify the importance of vugs permeability characterization. Therefore, injection test and pressure interference test among the wells could be considered to evaluate the local vugs permeability, extent, and interconnectivity. Porosity mapping derived from the seismic inversion could also be used in the succeeding task to characterize the lateral porosity distribution within the reservoir. With or without seismic inversion porosity mapping, it is worth exploring whether increased lateral heterogeneity plays a significant role in Potosi injectivity. Investigations on vugular, dolomitic outcrops suggest that there may be significantly greater lateral heterogeneity than what has been modeled here. Facies modeling within the Potosi has yet to be thoroughly addressed. The carbonates during the time of deposition are believed to be regionally extensive. However, it may be worth delineating the reservoir with other regional wells or modern day analogues to understand the extent of the Potosi. More specifically, the model could incorporate lateral changes or trends if deemed necessary to represent facies transition. Data acquisitions to characterize the fracture pressure gradient, the formation water properties, the relative permeability, and the capillary pressure could also be considered in order to allow a more rigorous evaluation of the Potosi storage performance. A simulation using several injectors could also be considered to determine the required number of wells to achieve the injection target while taking into account the pressure interference.

  11. Altering Reservoir Wettability to Improve Production from Single Wells

    SciTech Connect (OSTI)

    W. W. Weiss

    2006-09-30

    Many carbonate reservoirs are naturally fractured and typically produce less than 10% original oil in place during primary recovery. Spontaneous imbibition has proven an important mechanism for oil recovery from fractured reservoirs, which are usually weak waterflood candidates. In some situations, chemical stimulation can promote imbibition of water to alter the reservoir wettability toward water-wetness such that oil is produced at an economic rate from the rock matrix into fractures. In this project, cores and fluids from five reservoirs were used in laboratory tests: the San Andres formation (Fuhrman Masho and Eagle Creek fields) in the Permian Basin of Texas and New Mexico; and the Interlake, Stony Mountain, and Red River formations from the Cedar Creek Anticline in Montana and South Dakota. Solutions of nonionic, anionic, and amphoteric surfactants with formation water were used to promote waterwetness. Some Fuhrman Masho cores soaked in surfactant solution had improved oil recovery up to 38%. Most Eagle Creek cores did not respond to any of the tested surfactants. Some Cedar Creek anticline cores had good response to two anionic surfactants (CD 128 and A246L). The results indicate that cores with higher permeability responded better to the surfactants. The increased recovery is mainly ascribed to increased water-wetness. It is suspected that rock mineralogy is also an important factor. The laboratory work generated three field tests of the surfactant soak process in the West Fuhrman Masho San Andres Unit. The flawlessly designed tests included mechanical well clean out, installation of new pumps, and daily well tests before and after the treatments. Treatments were designed using artificial intelligence (AI) correlations developed from 23 previous surfactant soak treatments. The treatments were conducted during the last quarter of 2006. One of the wells produced a marginal volume of incremental oil through October. It is interesting to note that the field tests were conducted in an area of the field that has not met production expectations. The dataset on the 23 Phosphoria well surfactant soaks was updated. An analysis of the oil decline curves indicted that 4.5 lb of chemical produced a barrel of incremental oil. The AI analysis supports the adage 'good wells are the best candidates.' The generally better performance of surfactant in the high permeability core laboratory tests supports this observation. AI correlations were developed to predict the response to water-frac stimulations in a tight San Andres reservoir. The correlations maybe useful in the design of Cedar Creek Anticline surfactant soak treatments planned for next year. Nuclear Magnetic Resonance scans of dolomite cores to measure porosity and saturation during the high temperature laboratory work were acquired. The scans could not be correlated with physical measurement using either conventional or AI methods.

  12. Approaches to identifying reservoir heterogeneity and reserve growth opportunities from subsurface data: The Oficina Formation, Budare field, Venezuela

    SciTech Connect (OSTI)

    Hamilton, D.S.; Raeuchle, S.K.; Holtz, M.H.

    1997-08-01

    We applied an integrated geologic, geophysical, and engineering approach devised to identify heterogeneities in the subsurface that might lead to reserve growth opportunities in our analysis of the Oficina Formation at Budare field, Venezuela. The approach involves 4 key steps: (1) Determine geologic reservoir architecture; (2) Investigate trends in reservoir fluid flow; (3) Integrate fluid flow trends with reservoir architecture; and (4) Estimate original oil-in-place, residual oil saturation, and remaining mobile oil, to identify opportunities for reserve growth. There are three main oil-producing reservoirs in the Oficina Formation that were deposited in a bed-load fluvial system, an incised valley-fill, and a barrier-strandplain system. Reservoir continuity is complex because, in addition to lateral facies variability, the major Oficina depositional systems were internally subdivided by high-frequency stratigraphic surfaces. These surfaces define times of intermittent lacustrine and marine flooding events that punctuated the fluvial and marginal marine sedimentation, respectively. Syn and post depositional faulting further disrupted reservoir continuity. Trends in fluid flow established from initial fluid levels, response to recompletion workovers, and pressure depletion data demonstrated barriers to lateral and vertical fluid flow caused by a combination of reservoir facies pinchout, flooding shale markers, and the faults. Considerable reserve growth potential exists at Budare field because the reservoir units are highly compartment by the depositional heterogeneity and structural complexity. Numerous reserve growth opportunities were identified in attics updip of existing production, in untapped or incompletely drained compartments, and in field extensions.

  13. County, LANL consider colocation space

    Broader source: All U.S. Department of Energy (DOE) Office Webpages (Extended Search)

    County, LANL consider colocation space County, LANL consider colocation space The space will be geared toward a wide range of users: entrepreneurs, freelances, young professionals, small business, visiting corporate employees, LANL staff, LANL strategic partners and youth. April 24, 2016 The 2,400-square-foot facility at 150 Central Park Square will include a large open collaborative space, a private meeting room available for rent, a kitchen and "phone booths" for private

  14. Application of Advanced Reservoir Characterization, Simulation, and Production Optimization Strategies to Maximize Recovery in Slope and Basin Clastic Reservoirs, West Texas (Delaware Basin), Class III

    SciTech Connect (OSTI)

    Dutton, Shirley P.; Flanders, William A.

    2001-11-04

    The objective of this Class III project was demonstrate that reservoir characterization and enhanced oil recovery (EOR) by CO2 flood can increase production from slope and basin clastic reservoirs in sandstones of the Delaware Mountain Group in the Delaware Basin of West Texas and New Mexico. Phase 1 of the project, reservoir characterization, focused on Geraldine Ford and East Ford fields, which are Delaware Mountain Group fields that produce from the upper Bell Canyon Formation (Ramsey sandstone). The demonstration phase of the project was a CO2 flood conducted in East Ford field, which is operated by Orla Petco, Inc., as the East Ford unit.

  15. Encapsulated microsensors for reservoir interrogation

    DOE Patents [OSTI]

    Scott, Eddie Elmer; Aines, Roger D.; Spadaccini, Christopher M.

    2016-03-08

    In one general embodiment, a system includes at least one microsensor configured to detect one or more conditions of a fluidic medium of a reservoir; and a receptacle, wherein the receptacle encapsulates the at least one microsensor. In another general embodiment, a method include injecting the encapsulated at least one microsensor as recited above into a fluidic medium of a reservoir; and detecting one or more conditions of the fluidic medium of the reservoir.

  16. Advanced reservoir characterization in the Antelope Shale to establish the viability of CO{sub 2} enhanced oil recovery in California`s Monterey Formation siliceous shales. Annual report, February 12, 1996--February 11, 1997

    SciTech Connect (OSTI)

    Toronyi, R.M.

    1997-12-01

    The Buena Vista Hills field is located about 25 miles southwest of Bakersfield, in Kern County, California, about two miles north of the city of Taft, and five miles south of the Elk Hills field. The Antelope Shale zone was discovered at the Buena Vista Hills field in 1952, and has since been under primary production. Little research was done to improve the completion techniques during the development phase in the 1950s, so most of the wells are completed with about 1000 ft of slotted liner. The proposed pilot consists of four existing producers on 20 acre spacing with a new 10 acre infill well drilled as the pilot CO{sub 2} injector. Most of the reservoir characterization of the first phase of the project will be performed using data collected in the pilot pattern wells. This is the first annual report of the project. It covers the period February 12, 1996 to February 11, 1997. During this period the Chevron Murvale 653Z-26B well was drilled in Section 26-T31S/R23E in the Buena Vista Hills field, Kern County, California. The Monterey Formation equivalent Brown and Antelope Shales were continuously cored, the zone was logged with several different kinds of wireline logs, and the well was cased to a total depth of 4907 ft. Core recovery was 99.5%. Core analyses that have been performed include Dean Stark porosity, permeability and fluid saturations, field wettability, anelastic strain recovery, spectral core gamma, profile permeametry, and photographic imaging. Wireline log analysis includes mineral-based error minimization (ELAN), NMR T2 processing, and dipole shear wave anisotropy. A shear wave vertical seismic profile was acquired after casing was set and processing is nearly complete.

  17. EXPERIMENTAL AND THEORETICAL DETERMINATION OF HEAVY OIL VISCOSITY...

    Office of Scientific and Technical Information (OSTI)

    EXPERIMENTAL AND THEORETICAL DETERMINATION OF HEAVY OIL VISCOSITY UNDER RESERVOIR CONDITIONS FINAL PROGRESS REPORT PERIOD: OCT 1999-MAY 2003 CONTRACT NUMBER: DE-FG26-99FT40615 ...

  18. Heavy and Thermal Oil Recovery Production Mechanisms, SUPRI TR-127

    SciTech Connect (OSTI)

    Kovscek, Anthony R.; Brigham, William E.; Castanier, Louis M.

    2001-09-07

    The program spans a spectrum of topics and is divided into five categories: (i) multiphase flow and rock properties, (ii) hot fluid injection, (iii) primary heavy-oil production, (iv) reservoir definition, and (v) in-situ combustion.

  19. Using Chemicals to Optimize Conformance Control in Fractured Reservoirs

    SciTech Connect (OSTI)

    Seright, Randall; Liang, Jenn-Tai; Schrader, Richard; Hagstrom II, John; Wang, Ying; Kumar, Anand; Wavrik, Kathryn

    2001-09-07

    The objectives of this project are: (1) to develop a capability to predict and optimize the ability of gels to reduce permeability to water more than that to oil or gas, (2) to develop procedures for optimizing blocking agent placement in wells where hydraulic fractures cause channeling problems, and (3) to develop procedures to optimize blocking agent placement in naturally fractured reservoirs. Work was directed at both injection wells and production wells and at vertical, horizontal, and highly deviated wells.

  20. Gypsy Field project in reservoir characterization. Final report

    SciTech Connect (OSTI)

    O`Meara, Jr., D. J.

    1997-05-01

    The overall objective of this project is to use the extensive Gypsy Field laboratory and data set as a focus for developing and testing reservoir characterization methods that are targeted at improved recovery of conventional oil. The Gypsy Field laboratory consists of coupled outcrop and subsurface sites which have been characterized to a degree of detail not possible in a production operation. Data from these sites entail geological descriptions, core measurements, well logs, vertical seismic surveys, a 3D seismic survey, crosswell seismic surveys, and pressure transient well tests. The overall project consists of four interdisciplinary sub-projects which are closely interlinked: modeling depositional environments; sweep efficiency; tracer testing; and integrated 3D seismic interpretation. The first of these aims at improving the ability to model complex depositional environments which trap movable oil. The second is a development geophysics project which proposes to improve the quality of reservoir geological models through better use of 3D seismic data. The third investigates the usefulness of a new numerical technique for identifying unswept oil through rapid calculation of sweep efficiency in large reservoir models. The fourth explores what can be learned from tracer tests in complex depositional environments, particularly those which are fluvial dominated.

  1. Assessing the Effect of Timing of Availability for Carbon Dioxide Storage in the Largest Oil and Gas Pools in the Alberta Basin: Description of Data and Methodology

    SciTech Connect (OSTI)

    Dahowski, Robert T.; Bachu, Stefan

    2007-03-05

    Carbon dioxide capture from large stationary sources and storage in geological media is a technologically-feasible mitigation measure for the reduction of anthropogenic emissions of CO2 to the atmosphere in response to climate change. Carbon dioxide (CO2) can be sequestered underground in oil and gas reservoirs, in deep saline aquifers, in uneconomic coal beds and in salt caverns. The Alberta Basin provides a very large capacity for CO2 storage in oil and gas reservoirs, along with significant capacity in deep saline formations and possible unmineable coal beds. Regional assessments of potential geological CO2 storage capacity have largely focused so far on estimating the total capacity that might be available within each type of reservoir. While deep saline formations are effectively able to accept CO2 immediately, the storage potential of other classes of candidate storage reservoirs, primarily oil and gas fields, is not fully available at present time. Capacity estimates to date have largely overlooked rates of depletion in these types of storage reservoirs and typically report the total estimated storage capacity that will be available upon depletion. However, CO2 storage will not (and cannot economically) begin until the recoverable oil and gas have been produced via traditional means. This report describes a reevaluation of the CO2 storage capacity and an assessment of the timing of availability of the oil and gas pools in the Alberta Basin with very large storage capacity (>5 MtCO2 each) that are being looked at as likely targets for early implementation of CO2 storage in the region. Over 36,000 non-commingled (i.e., single) oil and gas pools were examined with effective CO2 storage capacities being individually estimated. For each pool, the life expectancy was estimated based on a combination of production decline analysis constrained by the remaining recoverable reserves and an assessment of economic viability, yielding an estimated depletion date, or year that it will be available for CO2 storage. The modeling framework and assumptions used to assess the impact of the timing of CO2 storage resource availability on the regions deployment of CCS technologies is also described. The purpose of this report is to describe the data and methodology for examining the carbon dioxide (CO2) storage capacity resource of a major hydrocarbon province incorporating estimated depletion dates for its oil and gas fields with the largest CO2 storage capacity. This allows the development of a projected timeline for CO2 storage availability across the basin and enables a more realistic examination of potential oil and gas field CO2 storage utilization by the regions large CO2 point sources. The Alberta Basin of western Canada was selected for this initial examination as a representative mature basin, and the development of capacity and depletion date estimates for the 227 largest oil and gas pools (with a total storage capacity of 4.7 GtCO2) is described, along with the impact on source-reservoir pairing and resulting CO2 transport and storage economics. The analysis indicates that timing of storage resource availability has a significant impact on the mix of storage reservoirs selected for utilization at a given time, and further confirms the value that all available reservoir types offer, providing important insights regarding CO2 storage implementation to this and other major oil and gas basins throughout North America and the rest of the world. For CCS technologies to deploy successfully and offer a meaningful contribution to climate change mitigation, CO2 storage reservoirs must be available not only where needed (preferably co-located with or near large concentrations of CO2 sources or emissions centers) but also when needed. The timing of CO2 storage resource availability is therefore an important factor to consider when assessing the real opportunities for CCS deployment in a given region.

  2. MAPPING OF RESERVOIR PROPERTIES AND FACIES THROUGH INTEGRATION OF STATIC AND DYNAMIC DATA

    SciTech Connect (OSTI)

    Albert C. Reynolds; Dean S. Oliver; Fengjun Zhang; Yannong Dong; Jan Arild Skjervheim; Ning Liu

    2003-01-01

    Knowledge of the distribution of permeability and porosity in a reservoir is necessary for the prediction of future oil production, estimation of the location of bypassed oil, and optimization of reservoir management. But while the volume of data that can potentially provide information on reservoir architecture and fluid distributions has increased enormously in the past decade, it is not yet possible to make use of all the available data in an integrated fashion. While it is relatively easy to generate plausible reservoir models that honor static data such as core, log, and seismic data, it is far more difficult to generate plausible reservoir models that honor dynamic data such as transient pressures, saturations, and flow rates. As a result, the uncertainty in reservoir properties is higher than it could be and reservoir management can not be optimized. The goal of this project is to develop computationally efficient automatic history matching techniques for generating geologically plausible reservoir models which honor both static and dynamic data. Solution of this problem is necessary for the quantification of uncertainty in future reservoir performance predictions and for the optimization of reservoir management. Facies (defined here as regions of relatively uniform petrophysical properties) are common features of all reservoirs. Because the flow properties of the various facies can vary greatly, knowledge of the location of facies boundaries is of utmost importance for the prediction of reservoir performance and for the optimization of reservoir management. When the boundaries between facies are fairly well known, but flow properties are poorly known, the average properties for all facies can be determined using traditional techniques. Traditional history matching honors dynamic data by adjusting petrophysical properties in large areas, but in the process of adjusting the reservoir model ignores the static data and often results in implausible reservoir models. In general, boundary locations, average permeability and porosity, relative permeability curves, and local flow properties may all need to be adjusted to achieve a plausible reservoir model that honors all data. In this project, we will characterize the distribution of geologic facies as an indicator random field, making use of the tools of geostatistics as well as the tools of inverse and probability theory for data integration.

  3. Quantification of Libby Reservoir Levels Needed to Maintain or Enhance Reservoir Fisheries, 1985 Annual Report.

    SciTech Connect (OSTI)

    Chisholm, Ian

    1985-01-01

    The goal was to quantify seasonal water levels needed to maintain or enhance the reservoir fishery in Libby. This report summarizes data collected from July 1984 through July 1985, and, where appropriate, presents data collected since 1983. The Canada, Rexford, and Tenmile areas of the reservoir are differentially affected by drawdown. Relative changes in water volume and surface area are greatest in the Canada area and smallest in the Tenmile area. Reservoir morphology and hydraulics probably play a major role in fish distribution through their influence on water temperature. Greatest areas of habitat with optimum water temperature for Salmo spp. and kokanee occurred during the spring and fall months. Dissolved oxygen, pH and conductivity levels were not limiting during any sampling period. Habitat enhancement work was largely unsuccessful. Littoral zone vegetation plantings did not survive well, primarily the result of extreme water level fluctuations. Relative abundances of fish species varied seasonally within and between the three areas. Water temperature is thought to be the major influence in fish distribution patterns. Other factors, such as food availability and turbidity, may mitigate its influence. Sampling since 1975 illustrates a continued increase in kokanee numbers and a dramatic decline in redside shiners. Salmo spp., bull trout, and burbot abundances are relatively low while peamouth and coarsescale sucker numbers remain high. A thermal dynamics model and a trophic level components model will be used to quantify the impact of reservoir operation on the reservoir habitat, primary production, secondary production and fish populations. Particulate carbon will be used to track energy flow through trophic levels. A growth-driven population dynamics simulation model that will estimate the impacts of reservoir operation on fish population dynamics is also being considered.

  4. Data Integration for the Generation of High Resolution Reservoir Models

    SciTech Connect (OSTI)

    Albert Reynolds; Dean Oliver; Gaoming Li; Yong Zhao; Chaohui Che; Kai Zhang; Yannong Dong; Chinedu Abgalaka; Mei Han

    2009-01-07

    The goal of this three-year project was to develop a theoretical basis and practical technology for the integration of geologic, production and time-lapse seismic data in a way that makes best use of the information for reservoir description and reservoir performance predictions. The methodology and practical tools for data integration that were developed in this research project have been incorporated into computational algorithms that are feasible for large scale reservoir simulation models. As the integration of production and seismic data require calibrating geological/geostatistical models to these data sets, the main computational tool is an automatic history matching algorithm. The following specific goals were accomplished during this research. (1) We developed algorithms for calibrating the location of the boundaries of geologic facies and the distribution of rock properties so that production and time-lapse seismic data are honored. (2) We developed and implemented specific procedures for conditioning reservoir models to time-lapse seismic data. (3) We developed and implemented algorithms for the characterization of measurement errors which are needed to determine the relative weights of data when conditioning reservoir models to production and time-lapse seismic data by automatic history matching. (4) We developed and implemented algorithms for the adjustment of relative permeability curves during the history matching process. (5) We developed algorithms for production optimization which accounts for geological uncertainty within the context of closed-loop reservoir management. (6) To ensure the research results will lead to practical public tools for independent oil companies, as part of the project we built a graphical user interface for the reservoir simulator and history matching software using Visual Basic.

  5. The Stimulation of Hydrocarbon Reservoirs with Subsurface Nuclear Explosions

    SciTech Connect (OSTI)

    LORENZ,JOHN C.

    2000-12-08

    Between 1965 and 1979 there were five documented and one or more inferred attempts to stimulate the production from hydrocarbon reservoirs by detonating nuclear devices in reservoir strata. Of the five documented tests, three were carried out by the US in low-permeability, natural-gas bearing, sandstone-shale formations, and two were done in the USSR within oil-bearing carbonates. The objectives of the US stimulation efforts were to increase porosity and permeability in a reservoir around a specific well by creating a chimney of rock rubble with fractures extending beyond it, and to connect superimposed reservoir layers. In the USSR, the intent was to extensively fracture an existing reservoir in the more general vicinity of producing wells, again increasing overall permeability and porosity. In both countries, the ultimate goals were to increase production rates and ultimate recovery from the reservoirs. Subsurface explosive devices ranging from 2.3 to about 100 kilotons were used at depths ranging from 1208 m (3963 ft) to 2568 m (8427 ft). Post-shot problems were encountered, including smaller-than-calculated fracture zones, formation damage, radioactivity of the product, and dilution of the BTU value of tie natural gas with inflammable gases created by the explosion. Reports also suggest that production-enhancement factors from these tests fell short of expectations. Ultimately, the enhanced-production benefits of the tests were insufficient to support continuation of the pro-grams within increasingly adversarial political, economic, and social climates, and attempts to stimulate hydrocarbon reservoirs with nuclear devices have been terminated in both countries.

  6. DOE - Office of Legacy Management -- Mobil Oil Corp - VA 01

    Office of Legacy Management (LM)

    Mobil Oil Corp - VA 01 FUSRAP Considered Sites Site: Mobil Oil Corp. (VA.01 ) Eliminated from further consideration under FUSRAP Designated Name: Not Designated Alternate Name: ...

  7. Research needs for strandplain/barrier island reservoirs in the United States

    SciTech Connect (OSTI)

    Cole, E.L.; Fowler, M.L.; Salamy, S.P.; Sarathi, P.S.; Young, M.A.

    1994-12-01

    This report identifies reservoir characterization and reservoir management research needs and IOR process and related research needs for the fourth geologic class, strandplain/barrier island reservoirs. The 330 Class 4 reservoirs in the DOE Tertiary OH Recovery Information System (TORIS) database contain about 30.8 billion barrels of oil or about 9% of the total original oil-in-place (OOIP) in all United States reservoirs. The current projection of Class 4 ultimate recovery with current operations is only 38% of the OOIP, leaving 19 billion barrels as the target for future IOR projects. Using the TORIS database and its predictive and economic models, the recovery potential which could result from future application of IOR technologies to Class 4 reservoirs was estimated to be between 1.0 and 4.3 billion barrels, depending on oil price and the level of technology advancement. The analysis indicated that this potential could be realized through (1) infill drilling alone and in combination with polymer flooding and profile modification, (2) chemical flooding (surfactant), and (3) thermal processes. Most of this future potential is in Texas, Oklahoma, California, and the Rocky Mountain region. Approximately two-thirds of the potentially recoverable resource is at risk of abandonment by the year 2000, which emphasizes the urgent need for the development and demonstration of cost-effective recovery technologies.

  8. Water resources review: Ocoee reservoirs, 1990

    SciTech Connect (OSTI)

    Cox, J.P.

    1990-08-01

    Tennessee Valley Authority (TVA) is preparing a series of reports to make technical information on individual TVA reservoirs readily accessible. These reports provide a summary of reservoir purpose and operation; physical characteristics of the reservoir and watershed; water quality conditions; aquatic biological conditions; and designated, actual and potential uses of the reservoir and impairments of those use. This reservoir status report addressed the three Ocoee Reservoirs in Polk County, Tennessee.

  9. Collapsible sheath fluid reservoirs for flow cytometers

    DOE Patents [OSTI]

    Mark, Graham A. (Los Alamos, NM)

    2000-01-01

    The present invention is a container in the form of a single housing for holding fluid, including a first collapsible reservoir having a first valve. The first reservoir initially contains a volume of fluid. The container also includes a second reservoir, initially empty (or substantially empty), expandable to a second volume. The second reservoir has a second valve. As the volume of said first reservoir decreases, the volume of the second reservoir proportionally increases.

  10. Simulation studies to evaluate the effect of fracture closure on the performance of naturally fractured reservoirs. Annual report

    SciTech Connect (OSTI)

    Not Available

    1991-10-01

    The first of a three-year research program to evaluate the effect of fracture closure on the recovery of oil and gas from naturally fractured reservoirs has been completed. The objectives of the study are to (1) evaluate the reservoir conditions where fracture closure is significant, and (2) evaluate innovative fluid injection techniques capable of maintaining pressure within the reservoir. Simulation studies were conducted with a dual porosity simulator capable of simulating the performance of vertical and horizontal wells. Each simulator was initialized using properties typical of the Austin Chalk reservoir in Pearsall Field, Texas. Simulations of both vertical and horizontal well performance were made assuming that fracture permeability was insensitive to pressure change. Sensitivity runs indicate that the simulator is predicting the effects of critical reservoir parameters in a logical and consistent manner. The results to-date confirm that horizontal wells can increase both oil recovery rate and total oil recovery from naturally fractured reservoirs. The year one simulation results will provide the baseline for the ongoing study which will evaluate the performance degradation caused by the sensitivity of fracture permeability to pressure change, and investigate fluid injection pressure maintenance as a means to improve oil recovery performance. The study is likely to conclude that fracture closure decreases oil recovery and that pressure support achieved through fluid injection could be beneficial in improving recovery.

  11. Los Alamos National Laboratory considers the use of biodiesel.

    SciTech Connect (OSTI)

    Matlin, M. K.

    2002-01-01

    A new EPA-approved alternative fuel, called biodiesel, may soon be used at Los Alamos National Laboratory in everything from diesel trucks to laboratory equipment. Biodiesel transforms vegetable oils into a renewable, cleaner energy source that can be used in any machinery that uses diesel fuel. For the past couple years, the Laboratory has been exploring the possibility of switching over to soybean-based biodiesel. This change could lead to many health and environmental benefits, as well as help reduce the nation's dependence on foreign oil. Biodiesel is a clean, renewable diesel fuel substitute made from soybean and other vegetable oil crops, as well as from recycled cooking oils. A chemical process breaks down the vegetable oil into a usable form. Vegetable oil has a chain of about 18 carbons and ordinary diesel has about 12 or 13 carbons. The process breaks the carbon chains of the vegetable oil and separates out the glycerin (a fatty substance used in creams and soaps). The co-product of glycerin can be used by pharmaceutical and cosmetic companies, as well as many other markets. Once the chains are shortened and the glycerin is removed from the oil, the remaining liquid is similar to petroleum diesel fuel. It can be burned in pure form or in a blend of any proportion with petroleum diesel. To be considered an alternative fuel source by the EPA, the blend must be at least 20 percent biodiesel (B20). According to the U.S. Department of Energy (DOE), biodiesel is America's fastest growing alternative fuel.

  12. Reservoir-Stimulation Optimization with Operational Monitoring...

    Office of Energy Efficiency and Renewable Energy (EERE) Indexed Site

    Reservoir-Stimulation Optimization with Operational Monitoring for Creation of Enhanced Geothermal Systems Reservoir-Stimulation Optimization with Operational Monitoring for ...

  13. Supercritical Carbon Dioxide / Reservoir Rock Chemical Interactions...

    Open Energy Info (EERE)

    Supercritical Carbon Dioxide Reservoir Rock Chemical Interactions Jump to: navigation, search Geothermal Lab Call Projects for Supercritical Carbon Dioxide Reservoir Rock...

  14. Integrated geologic and engineering reservoir characterization of the Hutton Sandstone, Jackson region, Australia

    SciTech Connect (OSTI)

    Hamilton, D.S.; Holtz, M.H.; Yeh, J.

    1996-08-01

    An integrated geologic and engineering reservoir characterization study of the Hutton Sandstone was completed for the Jackson region, Eromanga Basin, Australia. Our approach involves four principal steps: (1) determine reservoir architecture within a high-resolution sequence stratigraphic framework, (2) investigate trends in reservoir fluid flow, (3) integrate fluid flow trends with reservoir architecture to identify fundamental reservoir heterogeneities, and (4) identify opportunities for reserve growth. Contrary to the existing perception, the Hutton Sandstone, a continental-scale bed-load fluvial system, does not behave as a large, homogeneous tank in which pistonlike displacement of produced oil occurs unimpeded by vertical migration of the aquifer. The sequence stratigraphic analysis identified numerous thin but widespread shale units, deposited during lacustrine flooding events that periodically interrupted episodes of coarse clastic Hutton deposition. These shales represent chronostratigraphically significant surfaces. More importantly, the trends established in reservoir fluid flow from monitoring aquifer encroachment, production response to water shut-off workovers, and differential depletion in Repeat Formation Tests indicate that these shale units act as efficient barriers to vertical fluid flow. Erosion of the upper part of the Hutton reservoir by the younger Birkhead mixed-load fluvial system caused further stratigraphic complexity and introduced additional barriers to vertical and lateral migration of mobile oil and aquifer encroachment. This integrated characterization targeted strategic infill and step-out drilling and recompletion candidates.

  15. Design and life-cycle considerations for unconventional-reservoir wells

    SciTech Connect (OSTI)

    Miskimins, J.L.

    2009-05-15

    This paper provides an overview of design and life-cycle considerations for certain unconventional-reservoir wells. An overview of unconventional-reservoir definitions is provided. Well design and life-cycle considerations are addressed from three aspects: upfront reservoir development, initial well completion, and well-life and long-term considerations. Upfront-reservoir-development issues discussed include well spacing, well orientation, reservoir stress orientations, and tubular metallurgy. Initial-well-completion issues include maximum treatment pressures and rates, treatment diversion, treatment staging, flowback and cleanup, and dewatering needs. Well-life and long-term discussions include liquid loading, corrosion, refracturing and associated fracture reorientation, and the cost of abandonment. These design considerations are evaluated with case studies for five unconventional-reservoir types: shale gas (Barnett shale), tight gas (Jonah feld), tight oil (Bakken play), coalbed methane (CBM) (San Juan basin), and tight heavy oil (Lost Hills field). In evaluating the life cycle and design of unconventional-reservoir wells, 'one size' does not fit all and valuable knowledge and a shortening of the learning curve can be achieved for new developments by studying similar, more-mature fields.

  16. REVIVING ABANDONED RESERVOIRS WITH HIGH-PRESSURE AIR INJECTION: APPLICATION IN A FRACTURED AND KARSTED DOLOMITE RESERVOIR

    SciTech Connect (OSTI)

    Robert Loucks; Steve Ruppel; Julia Gale; Jon Holder; Jon Olson; Deanna Combs; Dhiraj Dembla

    2004-06-01

    The Bureau of Economic Geology (BEG) and Goldrus Producing Company have assembled a multidisciplinary team of geoscientists and engineers to evaluate the applicability of high-pressure air injection (HPAI) in revitalizing a nearly abandoned carbonate reservoir in the Permian Basin of West Texas. The characterization phase of the project is utilizing geoscientists and petroleum engineers from the Bureau of Economic Geology (BEG) and the Department of Petroleum and Geosystems Engineering (both at The University of Texas at Austin) to define the controls on fluid flow in the reservoir as a basis for developing a reservoir model. This model will be used to define a field deployment plan that Goldrus, a small independent oil company, will implement by drilling both vertical and horizontal wells during the demonstration phase of the project. Additional reservoir data were to be generated during the demonstration phase to improve the accuracy of the reservoir model. The demonstration phase has been delayed by Goldrus because of funding problems. Since the first of the year, Goldrus has been active in searching for partners to help finance the project. To this end it has commissioned several small consulting studies to technically support its effort to secure a partner. After financial support is obtained, the demonstration phase of the project will proceed. Since just after the beginning of the year, BEG has curtailed project activities and spending of DOE funds except for the continued support of one engineering student. This student has now completed his work and has written a thesis describing his research (titled ''Stimulating enhanced oil recovery (EOR) by high-pressure air injection (HPAI) in west Texas light oil reservoir''). We plan to recommence our work on the project as soon as the operator obtains necessary funding to carry out the demonstration phase of the project. In order to complete all activities specified in the proposal, it will be necessary to request an extension of the project from the originally defined completion date. We are confident that Goldrus will obtain the necessary funding to continue and that we can complete the project if an extension is granted. We strongly believe that the results of this study will provide the impetus for a new approach to enhanced oil recovery in the Permian Basin and elsewhere in the United States.

  17. Exploration for basal Silurian reservoirs in western Illinois

    SciTech Connect (OSTI)

    Whitaker, S.T.; Howard, R.H.

    1995-07-31

    The discovery of two oil fields, Kellerville and Siloam, in shallow (600--675 ft deep) basal Silurian carbonates in 1958 and 1959 respectively, was the first new production in western Illinois since the discovery of the Devonian Hoing sandstone at Colmar-Plymouth field in 1914. A second, and more major, drilling boom in western Illinois resulted from official recognition in 1982 of a significant oil discovery in basal Silurian rocks at Buckhorn East oil field, later Buckhorn Consolidated. Within a relatively short time, numerous rigs were moving into western Illinois in the hopes of repeating the successes experienced at Buckhorn East. Unfortunately, there was no adequate geologic model that explained the oil accumulations in western Illinois. Basal Silurian reservoirs in western Illinois developed due to dolomitization of carbonate that filled shallow valleys incised in the underlying Maquoketa shale. Exploration for these reservoirs should utilize all of the clues that are presented here. It will be critical to continue gathering data from the area via quality wireline logs, cores, samples, and geophysical studies. It is unlikely that the Buckhorn-Siloam-Kellerville complex is unique in western Illinois.

  18. Reservoir class field demonstration. Publication and presentation bibliography

    SciTech Connect (OSTI)

    1997-12-01

    The Reservoir Class Field Demonstration Program was initiated in FY92 in response to rapidly declining domestic production and the realization that huge volumes of oil are being abandoned in reservoirs because of uneconomic production techniques. This program is just one of the critical elements of the National Oil Program necessary to move Improved Oil Recovery (IOR) technology from the conceptual stage through research, pilot scale field experiments, and full-scale field demonstrations to industry acceptance and commercialization. Both the successful results and failures of the field demonstrations will provide focus to concurrent research programs. Elements of the field demonstrations that are suitable for broad industry application are being communicated to the industry through the oil program`s technology transfer effort. As part of the technology transfer effort, this listing of publications and presentations by the project operators has been compiled by the US Department of energy`s (DOE) National Petroleum Technology Office (NPTO). The bibliography contains 240 citations for publications and a similar number of citations for presentations.

  19. Louisiana (with State Offshore) Crude Oil Reserves in Nonproducing

    U.S. Energy Information Administration (EIA) Indexed Site

    Reservoirs (Million Barrels) Crude Oil Reserves in Nonproducing Reservoirs (Million Barrels) Louisiana (with State Offshore) Crude Oil Reserves in Nonproducing Reservoirs (Million Barrels) Decade Year-0 Year-1 Year-2 Year-3 Year-4 Year-5 Year-6 Year-7 Year-8 Year-9 1990's NA NA 198 226 2000's 204 227 185 190 150 193 198 193 144 149 2010's 183 152 157 180 221 - = No Data Reported; -- = Not Applicable; NA = Not Available; W = Withheld to avoid disclosure of individual company data. Release

  20. Mississippi (with State Offshore) Crude Oil Reserves in Nonproducing

    U.S. Energy Information Administration (EIA) Indexed Site

    Reservoirs (Million Barrels) Crude Oil Reserves in Nonproducing Reservoirs (Million Barrels) Mississippi (with State Offshore) Crude Oil Reserves in Nonproducing Reservoirs (Million Barrels) Decade Year-0 Year-1 Year-2 Year-3 Year-4 Year-5 Year-6 Year-7 Year-8 Year-9 1990's NA NA 49 68 2000's 38 71 42 68 79 87 79 35 126 117 2010's 94 90 82 73 85 - = No Data Reported; -- = Not Applicable; NA = Not Available; W = Withheld to avoid disclosure of individual company data. Release Date: 11/19/2015

  1. California (with State Offshore) Crude Oil Reserves in Nonproducing

    U.S. Energy Information Administration (EIA) Indexed Site

    Reservoirs (Million Barrels) Crude Oil Reserves in Nonproducing Reservoirs (Million Barrels) California (with State Offshore) Crude Oil Reserves in Nonproducing Reservoirs (Million Barrels) Decade Year-0 Year-1 Year-2 Year-3 Year-4 Year-5 Year-6 Year-7 Year-8 Year-9 1990's NA NA 937 511 2000's 464 508 336 313 267 455 496 335 197 272 2010's 522 542 627 606 588 - = No Data Reported; -- = Not Applicable; NA = Not Available; W = Withheld to avoid disclosure of individual company data. Release

  2. Contracts for field projects and supporting research on enhanced oil recovery. Quarterly progress review No. 85, October 1, 1995--December 31, 1995

    SciTech Connect (OSTI)

    Godley, P.; Waisley, S.

    1996-12-01

    This documents presents progress on enhanced oil recovery programs and reservoir characterization programs. Information is presented on contract numbers, awards, investigators, and project managers.

  3. Geothermal Reservoir Dynamics - TOUGHREACT

    SciTech Connect (OSTI)

    Pruess, Karsten; Xu, Tianfu; Shan, Chao; Zhang, Yingqi; Wu,Yu-Shu; Sonnenthal, Eric; Spycher, Nicolas; Rutqvist, Jonny; Zhang,Guoxiang; Kennedy, Mack

    2005-03-15

    This project has been active for several years and has focused on developing, enhancing and applying mathematical modeling capabilities for fractured geothermal systems. The emphasis of our work has recently shifted towards enhanced geothermal systems (EGS) and hot dry rock (HDR), and FY05 is the first year that the DOE-AOP actually lists this project under Enhanced Geothermal Systems. Our overall purpose is to develop new engineering tools and a better understanding of the coupling between fluid flow, heat transfer, chemical reactions, and rock-mechanical deformation, to demonstrate new EGS technology through field applications, and to make technical information and computer programs available for field applications. The objectives of this project are to: (1) Improve fundamental understanding and engineering methods for geothermal systems, primarily focusing on EGS and HDR systems and on critical issues in geothermal systems that are difficult to produce. (2) Improve techniques for characterizing reservoir conditions and processes through new modeling and monitoring techniques based on ''active'' tracers and coupled processes. (3) Improve techniques for targeting injection towards specific engineering objectives, including maintaining and controlling injectivity, controlling non-condensable and corrosive gases, avoiding scale formation, and optimizing energy recovery. Seek opportunities for field testing and applying new technologies, and work with industrial partners and other research organizations.

  4. Process for tertiary oil recovery using tall oil pitch

    DOE Patents [OSTI]

    Radke, Clayton J.

    1985-01-01

    Compositions and process employing same for enhancing the recovery of residual acid crudes, particularly heavy crudes, by injecting a composition comprising caustic in an amount sufficient to maintain a pH of at least about 11, preferably at least about 13, and a small but effective amount of a multivalent cation for inhibiting alkaline silica dissolution with the reservoir. Preferably a tall oil pitch soap is included and particularly for the heavy crudes a polymeric mobility control agent.

  5. Fuel Oil",,,"Fuel Oil Consumption",,"Fuel Oil Expenditures"

    U.S. Energy Information Administration (EIA) Indexed Site

    1. Total Fuel Oil Consumption and Expenditures, 1999" ,"All Buildings Using Fuel Oil",,,"Fuel Oil Consumption",,"Fuel Oil Expenditures" ,"Number of Buildings (thousand)","Floorspac...

  6. Steamflooding in a waterdrive reservoir; Upper Tulare sands, South Belridge field

    SciTech Connect (OSTI)

    Dietrich, J.K. )

    1990-08-01

    A steamflood project in the strong edgewater-drive Upper Tulare reservoir at South Belridge recovered about 31% of the original oil in place (OOIP) at a cumulative steam/oil ratio (SOR) of 2.7 vol/vol. Seven years of downdip steam injection depressed water influx and created an oil bank updip from the injectors. Response continued under the influence of returning aquifer water and heat scavenging after the injectors were shut down. Numerical reservoir simulation of the historical steamflood performance indicate that the high production/injection capacity (P/I) ratio induced early water encroachment and partial quenching of the growing steam zone. Restarting downdip steam injection at much higher rates after 6 years without injection is shown to recover more oil than continuing the steamflood with either a seven-spot or inverted nine-spot pattern.

  7. Enhanced oil recovery and applied geoscience research program. [Quarterly] report, April 1--June 30, 1993

    SciTech Connect (OSTI)

    Thomas, C.P.

    1993-12-31

    The objectives of this research program are to develop microbial enhanced oil recovery (MEOR) systems for application to reservoirs containing medium to heavy oils and to evaluate reservoir wettability and its effects on oil recovery. The MEOR research goals include: (a) development of bacterial cultures that are effective for oil displacement under a broad range of reservoir conditions, (b) improved understanding of the mechanisms by which microbial systems displace oil under reservoir conditions, (c) determination of the feasibility of combining microbial systems with or following conventional enhanced oil recovery (EOR) processes, (d) development and implementation of industry cost-shared field demonstration projects for MEOR technology. The goals of the reservoir wettability project are to develop: (a) better methods for assessment of reservoir core wettability, (b) more certainty in relating laboratory core analysis procedures to field conditions, (c) a better understanding of the effects of reservoir matrix properties and heterogeneity on wettability, and (d) improved ability to predict and influence waterflood and EOR response through control of wettability in reservoirs.

  8. Depositional sequence analysis and sedimentologic modeling for improved prediction of Pennsylvanian reservoirs

    SciTech Connect (OSTI)

    Watney, W.L.

    1994-12-01

    Reservoirs in the Lansing-Kansas City limestone result from complex interactions among paleotopography (deposition, concurrent structural deformation), sea level, and diagenesis. Analysis of reservoirs and surface and near-surface analogs has led to developing a {open_quotes}strandline grainstone model{close_quotes} in which relative sea-level stabilized during regressions, resulting in accumulation of multiple grainstone buildups along depositional strike. Resulting stratigraphy in these carbonate units are generally predictable correlating to inferred topographic elevation along the shelf. This model is a valuable predictive tool for (1) locating favorable reservoirs for exploration, and (2) anticipating internal properties of the reservoir for field development. Reservoirs in the Lansing-Kansas City limestones are developed in both oolitic and bioclastic grainstones, however, re-analysis of oomoldic reservoirs provides the greatest opportunity for developing bypassed oil. A new technique, the {open_quotes}Super{close_quotes} Pickett crossplot (formation resistivity vs. porosity) and its use in an integrated petrophysical characterization, has been developed to evaluate extractable oil remaining in these reservoirs. The manual method in combination with 3-D visualization and modeling can help to target production limiting heterogeneities in these complex reservoirs and moreover compute critical parameters for the field such as bulk volume water. Application of this technique indicates that from 6-9 million barrels of Lansing-Kansas City oil remain behind pipe in the Victory-Northeast Lemon Fields. Petroleum geologists are challenged to quantify inferred processes to aid in developing rationale geologically consistent models of sedimentation so that acceptable levels of prediction can be obtained.

  9. Technological problems associated with subsea development of high pressure and high temperature hydrocarbon reservoirs

    SciTech Connect (OSTI)

    Grillo, P.; Natarajan, S.

    1996-12-31

    The paper analyzes the implications in design of subsea completion for exploitation of HP/HT hydrocarbon reservoirs. The paper characterizes limitations associated with current subsea technology for HP/HT applications and outlines the engineering and technological development considered necessary to demonstrate the viability of subsea production technology for the exploitation of HP/HT reservoirs.

  10. A reservoir management plan

    SciTech Connect (OSTI)

    Allis, R.G.

    1989-06-16

    There are numerous documented cases of extraction of fluids from the ground causing surface subsidence. The cases include groundwater, oil and gas, as well as geothermal fluid withdrawal. A recent comprehensive review of all types of man-induced land subsidence was published by the Geological Survey of America. At the early stages of a geothermal power development project it is standard practice in most countries for an environmental impact report to be required. The possibility of geothermal subsidence has to be addressed, and usually it falls on the geophysicists and/or geologists to make some predictions. The advice given is vital for planning the power plant location and the borefield pipe and drain layout. It is not so much the vertical settlement that occurs with subsidence but the accompanying horizontal ground strains that can do the most damage to any man-made structure.

  11. A field laboratory for improved oil recovery. Final report

    SciTech Connect (OSTI)

    Hildebrandt, A.F.; McDonald, J.; Claridge, E.; Killough, J.

    1992-09-01

    The purpose of Annex III of the Memorandum of Understanding, undertaken by the Houston Petroleum Research Center at the University of Houston, was to develop a field laboratory for research in improved oil recovery using a Gulf Coast reservoir in Texas. The participants: (1) make a field site selection and conducted a high resolution seismic survey in the demonstration field, (2) obtained characteristics of the reservoir (3) developed an evaluation of local flood efficiency in different parts of the demonstration reservoir, (4) used diverse methodology to evaluate the potential recovery of the remaining oil in the test reservoir, (5) developed cross-well seismic tomography, and (6) will transfer the learned technologies to oil operators through publication and workshops. This abstract is an overview of these tasks.

  12. Reservoir characterization of Pennsylvanian Sandstone Reservoirs. Annual report

    SciTech Connect (OSTI)

    Kelkar, M.

    1992-09-01

    This annual report describes the progress during the second year of a project on Reservoir Characterization of Pennsylvanian Sandstone Reservoirs. The report is divided into three sections: (i) reservoir description and scale-up procedures; (ii) outcrop investigation; (iii) in-fill drilling potential. The first section describes the methods by which a reservoir can be characterized, can be described in three dimensions, and can be scaled up with respect to its properties, appropriate for simulation purposes. The second section describes the progress on investigation of an outcrop. The outcrop is an analog of Bartlesville Sandstone. We have drilled ten wells behind the outcrop and collected extensive log and core data. The cores have been slabbed, photographed and the several plugs have been taken. In addition, minipermeameter is used to measure permeabilities on the core surface at six inch intervals. The plugs have been analyzed for the permeability and porosity values. The variations in property values will be tied to the geological descriptions as well as the subsurface data collected from the Glen Pool field. The third section discusses the application of geostatistical techniques to infer in-fill well locations. The geostatistical technique used is the simulated annealing technique because of its flexibility. One of the important reservoir data is the production data. Use of production data will allow us to define the reservoir continuities, which may in turn, determine the in-fill well locations. The proposed technique allows us to incorporate some of the production data as constraints in the reservoir descriptions. The technique has been validated by comparing the results with numerical simulations.

  13. MAJOR OIL PLAYS IN UTAH AND VICINITY

    SciTech Connect (OSTI)

    Thomas C. Chidsey Jr; Craig D. Morgan; Roger L. Bon

    2003-07-01

    Utah oil fields have produced over 1.2 billion barrels (191 million m{sup 3}). However, the 13.7 million barrels (2.2 million m{sup 3}) of production in 2002 was the lowest level in over 40 years and continued the steady decline that began in the mid-1980s. The Utah Geological Survey believes this trend can be reversed by providing play portfolios for the major oil producing provinces (Paradox Basin, Uinta Basin, and thrust belt) in Utah and adjacent areas in Colorado and Wyoming. Oil plays are geographic areas with petroleum potential caused by favorable combinations of source rock, migration paths, reservoir rock characteristics, and other factors. The play portfolios will include: descriptions and maps of the major oil plays by reservoir; production and reservoir data; case-study field evaluations; summaries of the state-of-the-art drilling, completion, and secondary/tertiary techniques for each play; locations of major oil pipelines; descriptions of reservoir outcrop analogs; and identification and discussion of land use constraints. All play maps, reports, databases, and so forth, produced for the project will be published in interactive, menu-driven digital (web-based and compact disc) and hard-copy formats. This report covers research activities for the third quarter of the first project year (January 1 through March 31, 2003). This work included gathering field data and analyzing best practices in the eastern Uinta Basin, Utah, and the Colorado portion of the Paradox Basin. Best practices used in oil fields of the eastern Uinta Basin consist of conversion of all geophysical well logs into digital form, running small fracture treatments, fingerprinting oil samples from each producing zone, running spinner surveys biannually, mapping each producing zone, and drilling on 80-acre (32 ha) spacing. These practices ensure that induced fractures do not extend vertically out of the intended zone, determine the percentage each zone contributes to the overall production of the well, identify areas that may be by-passed by a waterflood, and prevent rapid water breakthrough. In the eastern Paradox Basin, Colorado, optimal drilling, development, and production practices consist of increasing the mud weight during drilling operations before penetrating the overpressured Desert Creek zone; centralizing treatment facilities; and mixing produced water from pumping oil wells with non-reservoir water and injecting the mixture into the reservoir downdip to reduce salt precipitation, dispose of produced water, and maintain reservoir pressure to create a low-cost waterflood. During this quarter, technology transfer activities consisted of technical presentations to members of the Technical Advisory Board in Colorado and the Colorado Geological Survey. The project home page was updated on the Utah Geological Survey Internet web site.

  14. Oil and Gas Field Code Master List - Energy Information Administration

    U.S. Energy Information Administration (EIA) Indexed Site

    Oil and Gas Field Code Master List With Data for 2015 | Release Date: February 24, 2016 | Next Release Date: February 2017 Previous Issues Year: 2015 2014 2013 2012 2011 2010 2009 2008 2007 2006 2005 2004 2003 2002 2001 2000 1998 1997 1996 1995 Go Comprehensive listing of U.S. oil and gas field names. Oil and Gas Field Code Master List 2015 Definition of a Field A field is defined as "an area consisting of a single reservoir or multiple reservoirs all grouped on, or related to, the same

  15. An evaluation of known remaining oil resources in the United States: Appendix. Volume 10

    SciTech Connect (OSTI)

    1993-11-01

    Volume ten contains the following appendices: overview of improved oil recovery methods which covers enhanced oil recovery methods and advanced secondary recovery methods; the benefits of improved oil recovery, selected data for the analyzed states; and list of TORIS fields and reservoirs.

  16. Wettability and Oil Recovery by Imbibition and Viscous Displacement from Fractured and Heterogeneous Carbonates

    SciTech Connect (OSTI)

    Norman R. Morrow; Jill Buckley

    2006-04-01

    About one-half of U.S. oil reserves are held in carbonate formations. The remaining oil in carbonate reservoirs is regarded as the major domestic target for improved oil recovery. Carbonate reservoirs are often fractured and have great complexity even at the core scale. Formation evaluation and prediction is often subject to great uncertainty. This study addresses quantification of crude oil/brine/rock interactions and the impact of reservoir heterogeneity on oil recovery by spontaneous imbibition and viscous displacement from pore to field scale. Wettability-alteration characteristics of crude oils were measured at calcite and dolomite surfaces and related to the properties of the crude oils through asphaltene content, acid and base numbers, and refractive index. Oil recovery was investigated for a selection of limestones and dolomites that cover over three orders of magnitude in permeability and a factor of four variation in porosity. Wettability control was achieved by adsorption from crude oils obtained from producing carbonate reservoirs. The induced wettability states were compared with those measured for reservoir cores. The prepared cores were used to investigate oil recovery by spontaneous imbibition and viscous displacement. The results of imbibition tests were used in wettability characterization and to develop mass transfer functions for application in reservoir simulation of fractured carbonates. Studies of viscous displacement in carbonates focused on the unexpected but repeatedly observed sensitivity of oil recovery to injection rate. The main variables were pore structure, mobility ratio, and wettability. The potential for improved oil recovery from rate-sensitive carbonate reservoirs by increased injection pressure, increased injectivity, decreased well spacing or reduction of interfacial tension was evaluated.

  17. Use of hydrogen-free carbon monoxide with steam in recovery of heavy oil at low temperatures

    SciTech Connect (OSTI)

    Hyne, J. B.; Tyrer, J. D.

    1984-12-11

    A process for recovering oil from a subterranean heavy oil-containing reservoir is provided, wherein steam and carbon monoxide are injected into the reservoir at a temperature less than about 260/sup 0/ C. At these low temperatures, the steam and hydrogen-free carbon monoxide are found to react in the reservoir, by the water gas reaction, to form carbon dioxide and hydrogen. These products both have upgrading effects on the heavy oil, enhancing its quality and producibility. At the low temperatures of the process, gasification and polymerization of the heavy oil are minimized.

  18. HIGH-PRESSURE AIR INJECTION: APPLICATION IN A FRACTURED AND KARSTED DOLOMITE RESERVOIR

    SciTech Connect (OSTI)

    Robert Loucks; Steve Ruppel; Julia Gale; Jon Holder; Jon Olsen; Deanna Combs; Dhiraj Dembla; Leonel Gomez

    2003-12-10

    The Bureau of Economic Geology and Goldrus Producing Company have assembled a multidisciplinary team of geoscientists and engineers to evaluate the applicability of high-pressure air injection (HPAI) in revitalizing a nearly abandoned carbonate reservoir in the Permian Basin of West Texas. The characterization phase of the project is utilizing geoscientists and petroleum engineers from the Bureau of Economic Geology and the Department of Petroleum Engineering (both at The University of Texas at Austin) to define the controls on fluid flow in the reservoir as a basis for developing a reservoir model. This model will be used to define a field deployment plan that Goldrus, a small independent oil company, will implement by drilling both vertical and horizontal wells during the demonstration phase of the project. Additional reservoir data are being gathered during the demonstration phase to improve the accuracy of the reservoir model. The results of the demonstration will being closely monitored to provide a basis for improving the design of the HPAI field deployment plan. The results of the reservoir characterization field demonstration and monitoring program will be documented and widely disseminated to facilitate adoption of this technology by oil operators in the Permian Basin and elsewhere in the U.S.

  19. Reservoir compartmentalization and management strategies: Lessons learned in the Illinois basin

    SciTech Connect (OSTI)

    Grube, J.P.; Crockett, J.E.; Huff, B.G.

    1997-08-01

    A research project jointly sponsored by the US Department of Energy and the Illinois State Geological Survey focused on the Cypress and Aux Vases Formations (Mississippian), major clastic reservoirs in the Illinois Basin. Results from the research showed that understanding the nature and distribution of reservoir compartments, and using effective reservoir management strategies, can significantly improve recovery efficiencies from oil fields in this mature basin. Compartments can be most effectively drained where they are geologically well defined and reservoir management practices are coordinated through unified, compartment-wide, development programs. Our studies showed that the Cypress and Aux Vases reservoirs contain lateral and vertical permeability barriers forming compartments that range in size from isolated, interlaminated sandstone and shale beds to sandstone bodies tens of feet in thickness and more than a mile in length. Stacked or shingled, genetically similar sandstone bodies are commonly separated by thin impermeable intervals that can be difficult to distinguish on logs and can, therefore, cause correlation problems, even between wells drilled on spacing of less than ten acres. Lateral separation of sandstone bodies causes similar problems. Reservoir compartmentalization reduces primary and particularly secondary recovery by trapping pockets of by-passed or banked oil. Compartments can be detected by comparing recovery factors of genetically similar sandstone bodies within a field; using packers to separate commingled intervals and analyzing fluid recoveries and pressures; making detailed core-to-log calibrations that identify compartment boundaries; and analyzing pressure data from waterflood programs.

  20. Oil shale: The environmental challenges III

    SciTech Connect (OSTI)

    Petersen, K.K.

    1983-01-01

    This book presents the papers of a symposium whose purpose was to discuss the environmental and socio-economic aspects of oil shale development. Topics considered include oil shale solid waste disposal, modeling spent shale disposal, water management, assessing the effects of oil shale facilities on water quality, wastewater treatment and use at oil shale facilities, potential air emissions from oil shale retorting, the control of air pollutant emissions from oil shale facilities, oil shale air emission control, socioeconomic research, a framework for mitigation agreements, the Garfield County approach to impact mitigation, the relationship of applied industrial hygiene programs and experimental toxicology programs, and industrial hygiene programs.

  1. Considered Sites Overview | Department of Energy

    Office of Energy Efficiency and Renewable Energy (EERE) Indexed Site

    View Other Sites DOE maintains the Considered Sites Database to provide information to the ... FUSRAP Considered Sites Information in the Considered Sites Database documents eligibility ...

  2. Laboratory methods for enhanced oil recovery core floods

    SciTech Connect (OSTI)

    Robertson, E.P.; Bala, G.A.; Thomas, C.P.

    1994-03-01

    Current research at the Idaho National Engineering Laboratory (INEL) is investigating microbially enhanced oil recovery (MEOR) systems for application to oil reservoirs. Laboratory corefloods are invaluable in developing technology necessary for a field application of MEOR. Methods used to prepare sandstone cores for experimentation, coreflooding techniques, and quantification of coreflood effluent are discussed in detail. A technique to quantify the small volumes of oil associated with laboratory core floods is described.

  3. Application of Integrated Reservoir Management and Reservoir Characterization to Optimize Infill Drilling

    SciTech Connect (OSTI)

    1998-01-01

    Infill drilling if wells on a uniform spacing without regard to reservoir performance and characterization foes not optimize reservoir development because it fails to account for the complex nature of reservoir heterogeneities present in many low permeability reservoirs, and carbonate reservoirs in particular. New and emerging technologies, such as geostatistical modeling, rigorous decline curve analysis, reservoir rock typing, and special core analysis can be used to develop a 3-D simulation model for prediction of infill locations.

  4. Application of fractal theory in refined reservoir description for EOR pilot area

    SciTech Connect (OSTI)

    Yue Li; Yonggang Duan; Yun Li; Yuan Lu

    1997-08-01

    A reliable reservoir description is essential to investigate scenarios for successful EOR pilot test. Reservoir characterization includes formation composition, permeability, porosity, reservoir fluids and other petrophysical parameters. In this study, various new tools have been applied to characterize Kilamayi conglomerate formation. This paper examines the merits of various statistical methods for recognizing rock property correlation in vertical columns and gives out methods to determine fractal dimension including R/S analysis and power spectral analysis. The paper also demonstrates that there is obvious fractal characteristics in conglomerate reservoirs of Kilamayi oil fields. Well log data in EOR pilot area are used to get distribution profile of parameters including permeability, porosity, water saturation and shale content.

  5. Depositional sequence analysis and sedimentologic modeling for improved prediction of Pennsylvanian reservoirs (Annex 1)

    SciTech Connect (OSTI)

    Watney, W.L.

    1992-01-01

    Interdisciplinary studies of the Upper Pennsylvanian Lansing and Kansas City groups have been undertaken in order to improve the geologic characterization of petroleum reservoirs and to develop a quantitative understanding of the processes responsible for formation of associated depositional sequences. To this end, concepts and methods of sequence stratigraphy are being used to define and interpret the three-dimensional depositional framework of the Kansas City Group. The investigation includes characterization of reservoir rocks in oil fields in western Kansas, description of analog equivalents in near-surface and surface sites in southeastern Kansas, and construction of regional structural and stratigraphic framework to link the site specific studies. Geologic inverse and simulation models are being developed to integrate quantitative estimates of controls on sedimentation to produce reconstructions of reservoir-bearing strata in an attempt to enhance our ability to predict reservoir characteristics.

  6. Improved oil recovery in Mississippian carbonate reservoirs of...

    Office of Scientific and Technical Information (OSTI)

    ... Due to the rapid development of the field during the first 9 ... The PTTC short course involved well log analysis techniques ... and an online extended abstract (Gerlach and others, ...

  7. Table 5. U.S. proved reserves of crude oil and lease condensate, crude oil, and

    U.S. Energy Information Administration (EIA) Indexed Site

    U.S. proved reserves of crude oil and lease condensate, crude oil, and lease condensate, 2004-14" "million barrels" ,,,"Revisionsa","Net of Salesb"," "," ","New Reservoir",,,"Provedd","Change" ,,"Net","and","and",,"New Field","Discoveries","Totalc","Estimated","Reserves","from"

  8. Jurassic carbonate reservoirs of the Amu Darya Basin, Uzbekistan and Turkmenistan

    SciTech Connect (OSTI)

    Shein, V.S.; Fortunatova, N.K.; Neilson, J.E.

    1995-08-01

    The Amu Darya Basin is a world class hydrocarbon province. Current reserves estimates are 220 TCF of gas and 800 MMbbl of oil and condensate, 50% of which is reservoired in Late Jurassic carbonates. Exploration opportunities still exist in large parts of the basin which are relatively undrilled. Within the 100-600m thick carbonate sequence, reservoir facies include reefs, shelf grainstones and turbidite fares. The major seal are Kimmeridgian - Tithonian evaporates which are up to 1600m thick in the basin centre. Stratigraphic trapping is common and often enhanced by structural modifications. The reservoirs are in communication with a major gas-prone Early-Middle Jurassic source rock. Oil-prone source rocks are thought to occur in basinal sediments which are coeval with the Late Jurassic reservoirs. Carbonate sedimentation commenced during the Late Jurassic with the development of a ramp complex. This evolved into a rimmed shelf with barrier and pinnacle reefs. Several cycles of relative sea-level change (largely eustatic?) influence the carbonate ramp/shelf systems and effect the distribution of reservoir facies. Numerous empirical observations by VNIGNI scientists on carbonate successions have enabled them to develop mathematically calculated indices for facies and reservoir prediction, which have been applied successfully in the Amu Darya Basin. Reservoir quality in the limestones is strongly controlled by primary facies. Reefs and shelf grainstones display the best reservoir characteristics. Whilst many facies have good total porosity, it is only the reef and grainstone belts where connected porosity (with pore throats greater than 10um) becomes effective. Burial cements are rare. Freshwater solution and cementation has often improved or preserved primary porosity.

  9. Using Chemicals to Optimize Conformance Control in Fractured Reservoirs

    SciTech Connect (OSTI)

    Seright, Randall S.

    2000-09-20

    This research project has three objectives. The first objective is to develop a capability to predict and optimize the ability of gels to reduce permeability to water more than that to oil or gas. The second objective is to develop procedures for optimizing blocking agent placement in wells where hydraulic fractures cause channeling problems. The third objective is to develop procedures to optimize blocking agent placement in naturally fractured reservoirs. This research project consists of three tasks, each of which addresses one of the above objectives. This work is directed at both injection wells and production wells and at vertical, horizontal, and highly deviated wells.

  10. Microbial enhanced oil recovery and wettability research program

    SciTech Connect (OSTI)

    Thomas, C.P.; Bala, G.A.; Duvall, M.L.

    1991-07-01

    This report covers research results for the microbial enhanced oil recovery (MEOR) and wettability research program conducted by EG G Idaho, Inc. at the Idaho National Engineering Laboratory (INEL). The isolation and characterization of microbial species collected from various locations including target oil field environments is underway to develop more effective oil recovery systems for specific applications. The wettability research is a multi-year collaborative effort with the New Mexico Petroleum Recovery Research Center (NMPRRC), to evaluate reservoir wettability and its effects on oil recovery. Results from the wettability research will be applied to determine if alteration of wettability is a significant contributing mechanism for MEOR systems. Eight facultatively anaerobic surfactant producing isolates able to function in the reservoir conditions of the Minnelusa A Sands of the Powder River Basin in Wyoming were isolated from naturally occurring oil-laden environments. Isolates were characterized according to morphology, thermostability, halotolerance, growth substrates, affinity to crude oil/brine interfaces, degradative effects on crude oils, and biochemical profiles. Research at the INEL has focused on the elucidation of microbial mechanisms by which crude oil may be recovered from a reservoir and the chemical and physical properties of the reservoir that may impact the effectiveness of MEOR. Bacillus licheniformis JF-2 (ATCC 39307) has been used as a benchmark organism to quantify MEOR of medium weight crude oils (17.5 to 38.1{degrees}API) the capacity for oil recovery of Bacillus licheniformis JF-2 utilizing a sucrose-based nutrient has been elucidated using Berea sandstone cores. Spacial distribution of cells after microbial flooding has been analyzed with scanning electron microscopy. Also the effect of microbial surfactants on the interfacial tensions (IFT) of aqueous/crude oil systems has been measured. 87 refs., 60 figs., 15 tabs.

  11. Application of reservoir characterization and advanced technologies to improve recovery and economics in a lower quality shallow shelf Sand Andreas Reservoir: Quarterly technical report, January 1, 1997--March 31, 1997

    SciTech Connect (OSTI)

    Taylor, A.R., Hickman, T.S., Justice, J.J.

    1997-04-30

    The Class 2 Project at West Welch was designed to demonstrate the use of advanced technologies to enhance the economics of improved oil recovery (IOR) projects in lower quality Shallow Shelf Carbonate (SSC) reservoirs, resulting in recovery of additional oil that would otherwise be left in the reservoir at project abandonment. Accurate reservoir description is critical to the effective evaluation and efficient design of IOR projects in the heterogeneous SSC reservoirs. Therefore, the majority of Budget Period 1 was devoted to reservoir characterization. Technologies being demonstrated include: l.Advanced petrophysics 1547 2.Three-dimensional (3-D) seismic 3.Cross-well bore tomography 4.Advanced reservoir simulation 5.Carbon dioxide (CO{sub 2}) stimulation treatments 6.Hydraulic fracturing design and monitoring 7. Mobility control agents SUMMARY OF TECHNICAL PROGRESS West Welch Unit is one of four large waterflood units in the Welch Field in the northwestern portion of Dawson County, Texas. The Welch Field was discovered in the early 1940`s and produces oil under a solution gas drive mechanism from the San Andres formation at approximately 4800 ft. The field has been under waterflood for 30 years and a significant portion has been infill-drilled on 20-ac density. A 1982- 86 Pilot C0{sub 2} injection project in the offsetting South Welch Unit yielded positive results. Recent installation of a C0{sub 2} pipeline near the field allowed the phased development of a miscible CO injection project at the South Welch Unit.

  12. Potosi Reservoir Modeling; History and Recommendations

    SciTech Connect (OSTI)

    Smith, Valerie; Leetaru, Hannes

    2014-09-30

    As a part of a larger project co-funded by the United States Department of Energy (US DOE) to evaluate the potential of formations within the Cambro-Ordovician strata above the Mt. Simon as potential targets for carbon sequestration in the Illinois and Michigan Basins, the Illinois Clean Coal Institute (ICCI) requested Schlumberger to evaluate the potential injectivity and carbon dioxide (CO₂) plume size of the Cambrian Potosi Formation. The evaluation of this formation was accomplished using wireline data, core data, pressure data, and seismic data from two projects: the US DOE-funded Illinois Basin–Decatur Project being conducted by the Midwest Geological Sequestration Consortium in Macon County, Illinois, as well as data from the Illinois – Industrial Carbon Capture and Sequestration (IL-ICCS) project funded through the American Recovery and Reinvestment Act. In 2010, technical performance evaluations on the Cambrian Potosi Formation were performed through reservoir modeling. The data included formation tops from mud logs, well logs from the Verification Well 1 (VW1) and the Injection Well (CCS1), structural and stratigraphic formation from three dimensional (3D) seismic data, and field data from several waste water injection wells for the Potosi Formation. The intention was for two million tonnes per annum (MTPA) of CO₂ to be injected for 20 years into the Potosi Formation. In 2013, updated reservoir models for the Cambrian Potosi Formation were evaluated. The data included formation tops from mud logs, well logs from the CCS1, VW1, and Verification Well 2 (VW2) wells, structural and stratigraphic formation from a larger 3D seismic survey, and field data from several waste water injection wells for Potosi Formation. The objective is to simulate the injection of CO₂ at a rate 3.5 million tons per annum (3.2 million tonnes per annum [MTPA]) for 30 years 106 million tons (96 MT total) into the Potosi Formation. The Potosi geomodeling efforts have evolved from using data from a single well in 2010 to the inclusion of data from three wells in 2013 which largely leverage the porosity and permeability logs plus knowledge of lost circulation zones. The first Potosi model (Potosi Geobody Model 2010) attempted to use the available seismic inversion data to inform the geomodel and predict vugular zones in advance of drilling VW1. Lost circulation zones in VW1 came in as the geologists predicted. The model was not implemented in subsequent simulation work. To date, reservoir models used for flow simulation work have relied predominately on Gaussian distributed properties (porosity and permeability) and have employed a single injection well. Potosi Model 2013b incorporated the new VW2 logs, and exhibited an extra level of sophistication by delineating the vugular intervals. This method added further realism that likely represents the best reservoir approximation to date. Where the 2010 reservoir models were 10 by 10 mi (16 by 16 km) in area, the 2013 models were expanded in size to 30 by 30 mi (48 by 48 km). The latest reservoir simulations show that a minimum of four injectors might be required to meet target injection rates. Still, there is data that requires further scrutiny and modeling methodologies that require testing for the Potosi Formation. This work is currently ongoing, and the next phase of the reservoir modeling intends to implement valuable data like porosity derived from seismic inversion, seismically derived geobodies, or a combination of both to further define vugular zones and the porosity distribution within the Potosi Formation. Understanding the dual porosity, dual permeability character of the Potosi remains the greatest challenge in representing this formation. Further analysis of the FMI* fullbore formation microimager data may aid in assessing this uncertainty. The Potosi Formation is indeed an interesting formation, and recommendations to further characterize it are included in the following list: - Data acquisition to identify the vugs permeability, distribution, and interconnectivity could be considered to perform a more rigorous evaluation of the Potosi Formation injectivity and capacity. This could be achieved by performing an injection test on a vugular interval to determine the vugs permeability, and an interference test between wells to evaluate the local vugs extent and interconnectivity. - A thorough study of the available FMI data may reveal specifics on estimating the vug to matrix ratio. This estimate could be used to further condition the porosity distribution. Porosity logs alone might underestimate the formation’s porosity associated with vugs. Porosity mapping derived from the seismic inversion could also be used in the succeeding task to characterize the lateral porosity distribution within the reservoir. This could involve the geobody methodology previously attempted in 2010. With or without seismic inversion porosity mapping, it is worth exploring whether increased lateral heterogeneity plays a significant role in Potosi injectivity. Investigations on vugular, dolomitic outcrops suggest that there may be significantly greater lateral heterogeneity than what has been modeled here. - The FMI data also reveals the presence of and helps describe open fractures. The presence of fractures will further enhance the formation’s permeability. The task of leveraging this data in the geomodeling effort still remains. Under the best of circumstances, this data describing open fractures may be combined with seismic attributes to delineate fracture corridors. Fracture modeling would certainly add another layer of sophistication to the model. Its contribution and applicability remain to be explored. - Facies modeling within the Potosi has yet to be thoroughly addressed. The carbonates during the time of deposition are believed to be regionally extensive. However, it may be worth delineating the reservoir with other regional wells or modern day analogues to understand the extent of the Potosi. More specifically, the model could incorporate lateral changes or trends if deemed necessary to represent facies transition. - Currently there is no fracture gradient data available for the Potosi in the Decatur project area. The acquisition of the fracture pressure data could be considered to determine an appropriate maximum allowable bottomhole injection pressure. This would allow the evaluation of injectivity and the required number of wells in a more precise manner. - Special core analysis (SCAL) to determine the relative permeability and capillary pressure of the vugs and matrix could be considered to have a better estimation of the reservoir injectivity and plume extent. - Formation water sampling and analysis could be considered for the Potosi to estimate the water salinity and properties. A vertical flow performance evaluation could be considered for the succeeding task to determine the appropriate tubing size, the required injection tubing head pressure, and to investigate whether the corresponding well injection rate falls within the tubing erosional velocity limit. - A simulation using several injectors could also be considered to determine the required number of wells to achieve the injection target while taking into account the pressure interference.

  13. Advanced Reservoir Characterization and Evaluation of CO2 Gravity Drainage in the Naturally Fractured Spraberry Trend Area, Class III

    SciTech Connect (OSTI)

    Knight, Bill; Schechter, David S.

    2002-07-26

    The goal of this project was to assess the economic feasibility of CO2 flooding the naturally fractured Spraberry Trend Area in west Texas. This objective was accomplished through research in four areas: (1) extensive characterization of the reservoirs, (2) experimental studies of crude oil/brine/rock (COBR) interactions in the reservoirs, (3) reservoir performance analysis, and (4) experimental investigations on CO2 gravity drainage in Spraberry whole cores. This provides results of the final year of the six-year project for each of the four areas.

  14. Advanced Reservoir Characterization and Evaluation of CO{sub 2} Gravity Drainage in the Naturally Fractured Spraberry Trend Area

    SciTech Connect (OSTI)

    Schechter, D.S.

    1999-02-03

    The overall goal of this project is to assess the economic feasibility of CO{sub 2} flooding the naturally fractured Spraberry Trend Area in West Texas. This objective is being accomplished by conducting research in four areas: (1) extensive characterization of the reservoirs, (2) experimental studies of crude oil/brine/rock (COBR) interactions in the reservoirs, (3) reservoir performance analysis, and, (4) experimental investigations on CO2 gravity drainage in Spraberry whole cores. This report provides results of the third year of the five-year project for each of the four areas including a status report of field activities leading up to injection of CO2.

  15. Exsolution Enhanced Oil Recovery with Concurrent CO2 Sequestration

    SciTech Connect (OSTI)

    Zuo, Lin; Benson, Sally M.

    2013-01-01

    A novel EOR method using carbonated water injection followed by depressurization is introduced. Results from micromodel experiments are presented to demonstrate the fundamental principles of this oil recovery method. A depressurization process (1 MPa/hr) was applied to a micromodel following carbonated water injection (Ca ? 10-5). The exsolved CO2 in water-filled pores blocked water flow in swiped portions and displaced water into oil-filled pores. Trapped oil after the carbonated water injection was mobilized by sequentially invading water. This method's self-distributed mobility control and local clogging was tested in a sandstone sample under reservoir conditions. A 10% incremental oil recovery was achieved by lowering the pressure 2 MPa below the CO2 liberation pressure. Additionally, exsolved CO2 resides in the pores of a reservoir as an immobile phase with a high residual saturation after oil production, exhibiting a potential synergy opportunity between CO2 EOR and CO2 sequestration

  16. Australian developments in oil shale processing

    SciTech Connect (OSTI)

    Baker, G.L.

    1981-01-01

    This study gives some background on Australian oil shale deposits, briefly records some history of oil shale processing in the country and looks at the current status of the various proposals being considered to produce syncrudes from Australian oil shales. 5 refs.

  17. Tenth workshop on geothermal reservoir engineering: proceedings

    SciTech Connect (OSTI)

    Not Available

    1985-01-22

    The workshop contains presentations in the following areas: (1) reservoir engineering research; (2) field development; (3) vapor-dominated systems; (4) the Geysers thermal area; (5) well test analysis; (6) production engineering; (7) reservoir evaluation; (8) geochemistry and injection; (9) numerical simulation; and (10) reservoir physics. (ACR)

  18. MAJOR OIL PLAYS IN UTAH AND VICINITY

    SciTech Connect (OSTI)

    Thomas C. Chidsey; Craig D. Morgan; Kevin McClure; Grant C. Willis

    2003-09-01

    Utah oil fields have produced over 1.2 billion barrels (191 million m{sup 3}). However, the 13.7 million barrels (2.2 million m{sup 3}) of production in 2002 was the lowest level in over 40 years and continued the steady decline that began in the mid-1980s. The Utah Geological Survey believes this trend can be reversed by providing play portfolios for the major oil-producing provinces (Paradox Basin, Uinta Basin, and thrust belt) in Utah and adjacent areas in Colorado and Wyoming. Oil plays are geographic areas with petroleum potential caused by favorable combinations of source rock, migration paths, reservoir rock characteristics, and other factors. The play portfolios will include: descriptions and maps of the major oil plays by reservoir; production and reservoir data; case-study field evaluations; summaries of the state-of-the-art drilling, completion, and secondary/tertiary techniques for each play; locations of major oil pipelines; descriptions of reservoir outcrop analogs; and identification and discussion of land use constraints. All play maps, reports, databases, and so forth, produced for the project will be published in interactive, menu-driven digital (web-based and compact disc) and hard-copy formats. This report covers research activities for the fourth quarter of the first project year (April 1 through June 30, 2003). This work included describing outcrop analogs to the Jurassic Nugget Sandstone and Pennsylvanian Paradox Formation, the major oil producers in the thrust belt and Paradox Basin, respectively. Production-scale outcrop analogs provide an excellent view, often in three dimensions, of reservoir-facies characteristics and boundaries contributing to the overall heterogeneity of reservoir rocks. They can be used as a ''template'' for evaluation of data from conventional core, geophysical and petrophysical logs, and seismic surveys. The Nugget Sandstone was deposited in an extensive dune field that extended from Wyoming to Arizona. Outcrop analogs are found in the stratigraphically equivalent Navajo Sandstone of southern Utah which displays large-scale dunal cross-strata with excellent reservoir properties and interdunal features such as oases, wadi, and playa lithofacies with poor reservoir properties. Hydrocarbons in the Paradox Formation are stratigraphically trapped in carbonate buildups (or phylloid-algal mounds). Similar carbonate buildups are exposed in the Paradox along the San Juan River of southeastern Utah. Reservoir-quality porosity may develop in the types of facies associated with buildups such as troughs, detrital wedges, and fans, identified from these outcrops. When combined with subsurface geological and production data, these outcrop analogs can improve (1) development drilling and production strategies such as horizontal drilling, (2) reservoir-simulation models, (3) reserve calculations, and (4) design and implementation of secondary/tertiary oil recovery programs and other best practices used in the oil fields of Utah and vicinity. During this quarter, technology transfer activities consisted of exhibiting the project plans, objectives, and products at a booth at the 2003 annual convention of the American Association of Petroleum Geologists. The project home page was updated on the Utah Geological Survey Internet web site.

  19. Development of an In Situ Biosurfactant Production Technology for Enhanced Oil Recovery

    SciTech Connect (OSTI)

    M.J. McInerney; R.M. Knapp; Kathleen Duncan; D.R. Simpson; N. Youssef; N. Ravi; M.J. Folmsbee; T.Fincher; S. Maudgalya; Jim Davis; Sandra Weiland

    2007-09-30

    The long-term economic potential for enhanced oil recovery (EOR) is large with more than 300 billion barrels of oil remaining in domestic reservoirs after conventional technologies reach their economic limit. Actual EOR production in the United States has never been very large, less than 10% of the total U. S. production even though a number of economic incentives have been used to stimulate the development and application of EOR processes. The U.S. DOE Reservoir Data Base contains more than 600 reservoirs with over 12 billion barrels of unrecoverable oil that are potential targets for microbially enhanced oil recovery (MEOR). If MEOR could be successfully applied to reduce the residual oil saturation by 10% in a quarter of these reservoirs, more than 300 million barrels of oil could be added to the U.S. oil reserve. This would stimulate oil production from domestic reservoirs and reduce our nation's dependence on foreign imports. Laboratory studies have shown that detergent-like molecules called biosurfactants, which are produced by microorganisms, are very effective in mobilizing entrapped oil from model test systems. The biosurfactants are effective at very low concentrations. Given the promising laboratory results, it is important to determine the efficacy of using biosurfactants in actual field applications. The goal of this project is to move biosurfactant-mediated oil recovery from laboratory investigations to actual field applications. In order to meet this goal, several important questions must be answered. First, it is critical to know whether biosurfactant-producing microbes are present in oil formations. If they are present, then it will be important to know whether a nutrient regime can be devised to stimulate their growth and activity in the reservoir. If biosurfactant producers are not present, then a suitable strain must be obtained that can be injected into oil reservoirs. We were successful in answering all three questions. The specific objectives of the project were (1) to determine the prevalence of biosurfactant producers in oil reservoirs, and (2) to develop a nutrient regime that would stimulate biosurfactant production in the oil reservoir.

  20. Calibration of Seismic Attributes for Reservoir Characterization

    SciTech Connect (OSTI)

    Wayne D. Pennington

    2002-09-29

    The project, "Calibration of Seismic Attributes for Reservoir Characterization," is now complete. Our original proposed scope of work included detailed analysis of seismic and other data from two to three hydrocarbon fields; we have analyzed data from four fields at this level of detail, two additional fields with less detail, and one other 2D seismic line used for experimentation. We also included time-lapse seismic data with ocean-bottom cable recordings in addition to the originally proposed static field data. A large number of publications and presentations have resulted from this work, inlcuding several that are in final stages of preparation or printing; one of these is a chapter on "Reservoir Geophysics" for the new Petroleum Engineering Handbook from the Society of Petroleum Engineers. Major results from this project include a new approach to evaluating seismic attributes in time-lapse monitoring studies, evaluation of pitfalls in the use of point-based measurements and facies classifications, novel applications of inversion results, improved methods of tying seismic data to the wellbore, and a comparison of methods used to detect pressure compartments. Some of the data sets used are in the public domain, allowing other investigators to test our techniques or to improve upon them using the same data. From the public-domain Stratton data set we have demonstrated that an apparent correlation between attributes derived along 'phantom' horizons are artifacts of isopach changes; only if the interpreter understands that the interpretation is based on this correlation with bed thickening or thinning, can reliable interpretations of channel horizons and facies be made. From the public-domain Boonsville data set we developed techniques to use conventional seismic attributes, including seismic facies generated under various neural network procedures, to subdivide regional facies determined from logs into productive and non-productive subfacies, and we developed a method involving cross-correlation of seismic waveforms to provide a reliable map of the various facies present in the area. The Wamsutter data set led to the use of unconventional attributes including lateral incoherence and horizon-dependent impedance variations to indicate regions of former sand bars and current high pressure, respectively, and to evaluation of various upscaling routines. The Teal South data set has provided a surprising set of results, leading us to develop a pressure-dependent velocity relationship and to conclude that nearby reservoirs are undergoing a pressure drop in response to the production of the main reservoir, implying that oil is being lost through their spill points, never to be produced. Additional results were found using the public-domain Waha and Woresham-Bayer data set, and some tests of technologies were made using 2D seismic lines from Michigan and the western Pacific ocean.

  1. CALIBRATION OF SEISMIC ATTRIBUTES FOR RESERVOIR CHARACTERIZATION

    SciTech Connect (OSTI)

    Wayne D. Pennington; Horacio Acevedo; Aaron Green; Joshua Haataja; Shawn Len; Anastasia Minaeva; Deyi Xie

    2002-10-01

    The project, ''Calibration of Seismic Attributes for Reservoir Calibration,'' is now complete. Our original proposed scope of work included detailed analysis of seismic and other data from two to three hydrocarbon fields; we have analyzed data from four fields at this level of detail, two additional fields with less detail, and one other 2D seismic line used for experimentation. We also included time-lapse seismic data with ocean-bottom cable recordings in addition to the originally proposed static field data. A large number of publications and presentations have resulted from this work, including several that are in final stages of preparation or printing; one of these is a chapter on ''Reservoir Geophysics'' for the new Petroleum Engineering Handbook from the Society of Petroleum Engineers. Major results from this project include a new approach to evaluating seismic attributes in time-lapse monitoring studies, evaluation of pitfalls in the use of point-based measurements and facies classifications, novel applications of inversion results, improved methods of tying seismic data to the wellbore, and a comparison of methods used to detect pressure compartments. Some of the data sets used are in the public domain, allowing other investigators to test our techniques or to improve upon them using the same data. From the public-domain Stratton data set we have demonstrated that an apparent correlation between attributes derived along ''phantom'' horizons are artifacts of isopach changes; only if the interpreter understands that the interpretation is based on this correlation with bed thickening or thinning, can reliable interpretations of channel horizons and facies be made. From the public-domain Boonsville data set we developed techniques to use conventional seismic attributes, including seismic facies generated under various neural network procedures, to subdivide regional facies determined from logs into productive and non-productive subfacies, and we developed a method involving cross-correlation of seismic waveforms to provide a reliable map of the various facies present in the area. The Wamsutter data set led to the use of unconventional attributes including lateral incoherence and horizon-dependent impedance variations to indicate regions of former sand bars and current high pressure, respectively, and to evaluation of various upscaling routines. The Teal South data set has provided a surprising set of results, leading us to develop a pressure-dependent velocity relationship and to conclude that nearby reservoirs are undergoing a pressure drop in response to the production of the main reservoir, implying that oil is being lost through their spill points, never to be produced. Additional results were found using the public-domain Waha and Woresham-Bayer data set, and some tests of technologies were made using 2D seismic lines from Michigan and the western Pacific ocean.

  2. Application of advanced reservoir characterization, simulation, and production optimization strategies to maximize recovery in slope and basin clastic reservoirs, West Texas (Delaware Basin), Class III

    SciTech Connect (OSTI)

    Dutton, Shirley P.; Flanders, William A.; Zirczy, Helena H.

    2000-05-24

    The objective of this Class 3 project was to demonstrate that detailed reservoir characterization of slope and basin clastic reservoirs in sandstones of the Delaware Mountain Group in the Delaware Basin of West Texas and New Mexico is a cost effective way to recover a higher percentage of the original oil in place through strategic placement of infill wells and geologically based field development. Phase 1 of the project, reservoir characterization, was completed this year, and Phase 2 began. The project is focused on East Ford field, a representative Delaware Mountain Group field that produces from the upper Bell Canyon Formation (Ramsey sandstone). The field, discovered in 1960, is operated by Oral Petco, Inc., as the East Ford unit. A CO{sub 2} flood is being conducted in the unit, and this flood is the Phase 2 demonstration for the project.

  3. PIA - Northeast Home Heating Oil Reserve System (Heating Oil...

    Energy Savers [EERE]

    Northeast Home Heating Oil Reserve System (Heating Oil) PIA - Northeast Home Heating Oil Reserve System (Heating Oil) PIA - Northeast Home Heating Oil Reserve System (Heating Oil)...

  4. Unconventional Oil and Gas Resources

    SciTech Connect (OSTI)

    2006-09-15

    World oil use is projected to grow to 98 million b/d in 2015 and 118 million b/d in 2030. Total world natural gas consumption is projected to rise to 134 Tcf in 2015 and 182 Tcf in 2030. In an era of declining production and increasing demand, economically producing oil and gas from unconventional sources is a key challenge to maintaining global economic growth. Some unconventional hydrocarbon sources are already being developed, including gas shales, tight gas sands, heavy oil, oil sands, and coal bed methane. Roughly 20 years ago, gas production from tight sands, shales, and coals was considered uneconomic. Today, these resources provide 25% of the U.S. gas supply and that number is likely to increase. Venezuela has over 300 billion barrels of unproven extra-heavy oil reserves which would give it the largest reserves of any country in the world. It is currently producing over 550,000 b/d of heavy oil. Unconventional oil is also being produced in Canada from the Athabasca oil sands. 1.6 trillion barrels of oil are locked in the sands of which 175 billion barrels are proven reserves that can be recovered using current technology. Production from 29 companies now operating there exceeds 1 million barrels per day. The report provides an overview of continuous petroleum sources and gives a concise overview of the current status of varying types of unconventional oil and gas resources. Topics covered in the report include: an overview of the history of Oil and Natural Gas; an analysis of the Oil and Natural Gas industries, including current and future production, consumption, and reserves; a detailed description of the different types of unconventional oil and gas resources; an analysis of the key business factors that are driving the increased interest in unconventional resources; an analysis of the barriers that are hindering the development of unconventional resources; profiles of key producing regions; and, profiles of key unconventional oil and gas producers.

  5. THMC Modeling of EGS Reservoirs -- Continuum through Discontinuum...

    Office of Scientific and Technical Information (OSTI)

    Capturing Reservoir Stimulation, Evolution and Induced Seismicity Citation Details ... Capturing Reservoir Stimulation, Evolution and Induced Seismicity This work has ...

  6. THMC Modeling of EGS Reservoirs … Continuum through Discontinuum...

    Office of Energy Efficiency and Renewable Energy (EERE) Indexed Site

    Evolution and Induced Seismicity THMC Modeling of EGS Reservoirs Continuum through Discontinuum Representations: Capturing Reservoir Stimulation, Evolution and ...

  7. Sunset Reservoir Solar Power Plant | Open Energy Information

    Open Energy Info (EERE)

    Reservoir Solar Power Plant Facility Sunset Reservoir Sector Solar Facility Type Photovoltaic Developer Recurrent Energy Location San Francisco, California Coordinates...

  8. Development of Reservoir Characterization Techniques and Production Models for Exploiting Naturally Fractured Reservoirs

    SciTech Connect (OSTI)

    Wiggins, M.L.; Evans, R.D.; Brown, R.L.; Gupta, A.

    2001-03-28

    This report focuses on integrating geoscience and engineering data to develop a consistent characterization of the naturally fractured reservoirs. During this reporting period, effort was focused on relating seismic data to reservoir properties of naturally fractured reservoirs, scaling well log data to generate interwell descriptors of these reservoirs, enhancing and debugging a naturally fractured reservoir simulator, and developing a horizontal wellbore model for use in the simulator.

  9. Geological input to reservoir simulation, Champion Field, offshore Brunei

    SciTech Connect (OSTI)

    Carter, R.; Salahudin, S.; Ho, T.C.

    1994-07-01

    Brunei Shell Petroleum's giant Champion field is in a mature stage of development with about 23 yr of production history to date. The field comprises a complex sequence of Miocene shallow marine and deltaic layered clastic reservoirs cut by numerous growth faults. This study was aimed at providing a quantified estimate of the effect of lateral and vertical discontinuities within the I and J reservoirs on the recovery for both depletion drive and in a waterflood, with a view to identifying the optimal method of completing the development of the oil reserves in this area. Geological input to the ECLIPSE simulator was aimed at quantifying two key parameters: (1) STOIIP connected to the well bore and (2) permeability contrast. Connected STOIIP is a function of the domain size of interconnected sand bodies, and this parameter was quantified by the use of detailed sedimentology resulting in sand-body facies maps for each reservoir sublayer. Permeability contrast was quantified by using a wireline-log based algorithm, calibrated against core data, which improved the existing accuracy of permeability estimates in this part of the field. Results of simulation runs illustrate the importance of quantifying geologic heterogeneity and provide valuable information for future field development planning.

  10. Geothermal Reservoir Temperatures in Southeastern Idaho using Multicomponent Geothermometry

    SciTech Connect (OSTI)

    Neupane, Ghanashyam; Mattson, Earl D.; McLing, Travis L.; Palmer, Carl D.; Smith, Robert W.; Wood, Thomas R.; Podgorney, Robert K.

    2015-03-01

    Southeastern Idaho exhibits numerous warm springs, warm water from shallow wells, and hot water within oil and gas test wells that indicate a potential for geothermal development in the area. Although the area exhibits several thermal expressions, the measured geothermal gradients vary substantially (19 – 61 ºC/km) within this area, potentially suggesting a redistribution of heat in the overlying ground water from deeper geothermal reservoirs. We have estimated reservoir temperatures from measured water compositions using an inverse modeling technique (Reservoir Temperature Estimator, RTEst) that calculates the temperature at which multiple minerals are simultaneously at equilibrium while explicitly accounting for the possible loss of volatile constituents (e.g., CO2), boiling and/or water mixing. Compositions of a selected group of thermal waters representing southeastern Idaho hot/warm springs and wells were used for the development of temperature estimates. The temperature estimates in the the region varied from moderately warm (59 ºC) to over 175 ºC. Specifically, hot springs near Preston, Idaho resulted in the highest temperature estimates in the region.

  11. 4. International reservoir characterization technical conference

    SciTech Connect (OSTI)

    1997-04-01

    This volume contains the Proceedings of the Fourth International Reservoir Characterization Technical Conference held March 2-4, 1997 in Houston, Texas. The theme for the conference was Advances in Reservoir Characterization for Effective Reservoir Management. On March 2, 1997, the DOE Class Workshop kicked off with tutorials by Dr. Steve Begg (BP Exploration) and Dr. Ganesh Thakur (Chevron). Tutorial presentations are not included in these Proceedings but may be available from the authors. The conference consisted of the following topics: data acquisition; reservoir modeling; scaling reservoir properties; and managing uncertainty. Selected papers have been processed separately for inclusion in the Energy Science and Technology database.

  12. Enhanced oil recovery system

    DOE Patents [OSTI]

    Goldsberry, Fred L.

    1989-01-01

    All energy resources available from a geopressured geothermal reservoir are used for the production of pipeline quality gas using a high pressure separator/heat exchanger and a membrane separator, and recovering waste gas from both the membrane separator and a low pressure separator in tandem with the high pressure separator for use in enhanced oil recovery, or in powering a gas engine and turbine set. Liquid hydrocarbons are skimmed off the top of geothermal brine in the low pressure separator. High pressure brine from the geothermal well is used to drive a turbine/generator set before recovering waste gas in the first separator. Another turbine/generator set is provided in a supercritical binary power plant that uses propane as a working fluid in a closed cycle, and uses exhaust heat from the combustion engine and geothermal energy of the brine in the separator/heat exchanger to heat the propane.

  13. Geochemistry and habitat of oils in Italy

    SciTech Connect (OSTI)

    Novelli, L.; Mattavelli, L.

    1988-01-01

    Most of the onshore and offshore oil occurrences found in Italy have been systematically analyzed by different techniques, i.e., capillary gas chromatography, biological markers, and stable isotopes composition. On the basis of the above analyses, ten different groups of oil have been identified and geographically located. Subsequently, the influence of the various geological settings on generation and migration of these different groups of oils was investigated and is discussed here. Due to its complex geological and tectonic history, the Alpine-Apennine chain behaved differently with regard to oil generation and migration in different areas. In fact, the high temperatures reached by the Mesozoic source rocks underneath a stack of allochthonous thrust sheets and the insulting thermal blanket effect exerted by the same sheets on other younger source rocks above gave rise to generally light oils. Furthermore, in this unique geological setting, the most external thrust sheets locally acted as reservoirs of the foredeep regime. Foreland sequences acted as both reservoirs of the foredeep oils and as generative kitchens of liquid hydrocarbons if suitable source rocks were present and adequate burial was reached.

  14. Geological and reservoir characterization of shallow-shelf carbonate fields, Southern Paradox Basin, Utah

    SciTech Connect (OSTI)

    Chidsey, T.C. Jr.; Eby, D.E.

    1996-12-31

    The Paradox basin of Utah, Colorado, and Arizona contains nearly 100 small oil fields producing from carbonate mounds within the Pennsylvanian (Desmoinesian) Paradox Formation. These fields typically have one to three wells with primary per field production ranging from 700 MBO to 2 MMBO at a 15-20% recovery rate. Five fields (Anasazi, Mule, Blue Hogan, Heron North, and Runway) within the Navajo Nation of southeastern Utah have been evaluated for CO{sub 2}-flood projects based upon geological characterization and reservoir modeling. Conventional cores from the five fields show that three compositional reservoir types are present: (1) phylloid algal, (2) bioclastic calcarenite, and (3) bryozoan-dominated. Phylloid algal mounds are abundant in four of the five fields, and exhibit the best overall porosity and permeability. This mound type developed where shallow water depths and low energy allowed establishment of calcareous algal colonies possibly on paleohighs. The principal reservoir rock is algal bafflestone composed mostly of the phylloid Ivanovia and occasionally dolomitized. The Heron North field is a bioclastic calcarenite reservoir. It represents high-energy conditions resulting in carbonate beaches developed over foreshore carbonate rubble. The principal reservoir rocks are grainstones and rudstones having grain-selective dissolution and complete dolomitization. Bryozoan-dominated mounds present in Runway field developed in quiet, below wave-base settings that appear to be localized along Mississippian fault blocks trends. The principal reservoir rocks are bindstone and framestone with no dolomitization. The resulting model suggests that CO{sub 2} miscible flooding of these and other small carbonate reservoirs in the Paradox basin could significantly increase ultimate recovery of oil.

  15. Geological and reservoir characterization of shallow-shelf carbonate fields, Southern Paradox Basin, Utah

    SciTech Connect (OSTI)

    Chidsey, T.C. Jr. ); Eby, D.E. )

    1996-01-01

    The Paradox basin of Utah, Colorado, and Arizona contains nearly 100 small oil fields producing from carbonate mounds within the Pennsylvanian (Desmoinesian) Paradox Formation. These fields typically have one to three wells with primary per field production ranging from 700 MBO to 2 MMBO at a 15-20% recovery rate. Five fields (Anasazi, Mule, Blue Hogan, Heron North, and Runway) within the Navajo Nation of southeastern Utah have been evaluated for CO[sub 2]-flood projects based upon geological characterization and reservoir modeling. Conventional cores from the five fields show that three compositional reservoir types are present: (1) phylloid algal, (2) bioclastic calcarenite, and (3) bryozoan-dominated. Phylloid algal mounds are abundant in four of the five fields, and exhibit the best overall porosity and permeability. This mound type developed where shallow water depths and low energy allowed establishment of calcareous algal colonies possibly on paleohighs. The principal reservoir rock is algal bafflestone composed mostly of the phylloid Ivanovia and occasionally dolomitized. The Heron North field is a bioclastic calcarenite reservoir. It represents high-energy conditions resulting in carbonate beaches developed over foreshore carbonate rubble. The principal reservoir rocks are grainstones and rudstones having grain-selective dissolution and complete dolomitization. Bryozoan-dominated mounds present in Runway field developed in quiet, below wave-base settings that appear to be localized along Mississippian fault blocks trends. The principal reservoir rocks are bindstone and framestone with no dolomitization. The resulting model suggests that CO[sub 2] miscible flooding of these and other small carbonate reservoirs in the Paradox basin could significantly increase ultimate recovery of oil.

  16. Study on fine geological modelling of the fluvial sandstone reservoir in Daqing oilfield

    SciTech Connect (OSTI)

    Zhoa Han-Qing

    1997-08-01

    These paper aims at developing a method for fine reservoir description in maturing oilfields by using close spaced well logging data. The main productive reservoirs in Daqing oilfield is a set of large fluvial-deltaic deposits in the Songliao Lake Basin, characterized by multi-layers and serious heterogeneities. Various fluvial channel sandstone reservoirs cover a fairly important proportion of reserves. After a long period of water flooding, most of them have turned into high water cut layers, but there are considerable residual reserves within them, which are difficult to find and tap. Making fine reservoir description and developing sound a geological model is essential for tapping residual oil and enhancing oil recovery. The principal reason for relative lower precision of predicting model developed by using geostatistics is incomplete recognition of complex distribution of fluvial reservoirs and their internal architecture`s. Tasking advantage of limited outcrop data from other regions (suppose no outcrop data available in oilfield) can only provide the knowledge of subtle changing of reservoir parameters and internal architecture. For the specific geometry distribution and internal architecture of subsurface reservoirs (such as in produced regions) can be gained only from continuous infilling logging well data available from studied areas. For developing a geological model, we think the first important thing is to characterize sandbodies geometries and their general architecture`s, which are the framework of models, and then the slight changing of interwell parameters and internal architecture`s, which are the contents and cells of the model. An excellent model should possess both of them, but the geometry is the key to model, because it controls the contents and cells distribution within a model.

  17. Crude Oil

    U.S. Energy Information Administration (EIA) Indexed Site

    Barrels) Product: Crude Oil Liquefied Petroleum Gases Distillate Fuel Oil Residual Fuel Oil Still Gas Petroleum Coke Marketable Petroleum Coke Catalyst Petroleum Coke Other Petroleum Products Natural Gas Coal Purchased Electricity Purchased Steam Period: Annual Download Series History Download Series History Definitions, Sources & Notes Definitions, Sources & Notes Show Data By: Product Area 2009 2010 2011 2012 2013 2014 View History U.S. 0 0 0 0 0 0 1986-2014 East Coast (PADD 1) 0 0 0 0

  18. ,"Fuel Oil Consumption",,,"Fuel Oil Expenditures"

    U.S. Energy Information Administration (EIA) Indexed Site

    4. Fuel Oil Consumption and Expenditure Intensities for Non-Mall Buildings, 2003" ,"Fuel Oil Consumption",,,"Fuel Oil Expenditures" ,"per Building (gallons)","per Square Foot...

  19. ,"Fuel Oil Consumption",,,"Fuel Oil Expenditures"

    U.S. Energy Information Administration (EIA) Indexed Site

    2. Fuel Oil Consumption and Expenditure Intensities, 1999" ,"Fuel Oil Consumption",,,"Fuel Oil Expenditures" ,"per Building (gallons)","per Square Foot (gallons)","per Worker...

  20. Fire flood recovery process effects upon heavy oil properties

    SciTech Connect (OSTI)

    Reichert, C.; Fuhr, B.; Sawatzky, H.; Lefleur, R.; Verkoczy, B.; Soveran, D.; Jha, K.

    1988-06-01

    The steady decline in proven conventional oil deposits world wide has increased the emphasis on the use of heavy oil and bitumen. Most of the heavy oil and oil sand deposits share the common problem of providing very little or no primary production. They require a reduction in viscosity of the oil to make it flow. The oil in place and the reservoir characteristics are generally studied carefully to determine the design of the recovery process most applicable to the deposit and to evaluate its potential. Many of these same characteristics are also used to evaluate the oil with respect to upgrading, refining and final usage in the form of products. A variety of processes have been developed most of which utilize heat either in the form of steam or combustion to mobolize the oil in the reservoir. These processes vary considerably from rather mild conditions for steam stimulation to quite severe for combustion recovery. Figure 1 shows a typical schematic of an insitu combustion process. Many variations of forward combustion are used in the field to produce oil. Depending upon the severity of the recovery process in the recovered oil may be similar to the oil in the deposit or may be highly modified (oxidized, polymerized or upgraded). A memorandum of Understanding was signed by the Governments of the United States of America, Canada and the Provinces of Saskatchewan and Alberta to study different aspects of the problems related to the recovery of oil from heavy oil and sand deposits. One phase of the study is to determine the effects of different methods of in-situ recovery on the composition of recovered bitumen and heavy oils. This paper describes the findings from a study of fireflood process in a heavy oil deposit located in the Cummings formation of the Eyehill Field in Saskatchewan, Canada.

  1. Transient aspects of unloading oil and gas wells with coiled tubing

    SciTech Connect (OSTI)

    Gu, H.

    1995-12-31

    Unloading oil and gas wells with coiled tubing (CT) conveyed nitrogen circulation is a transient process in which the original heavier fluid in a wellbore is displaced by nitrogen and lighter reservoir fluid. The transient aspects need to be considered when determining nitrogen volume and operation time for unloading a well. A computer wellbore simulator has been developed and used to study the transient effects. The simulator includes transient multiphase mass transport and takes into account the different fluids in the wellbore and from the reservoir. The simulator also includes the gas rise in the wellbore liquid below the CT and can be used for gas well unloading. The transient results of oil and gas well unloading are presented. The effects of CT size and depth, workover fluid, and nitrogen rate and volume on unloading are discussed. Unlike continuous gas lift, the total gas volume needed and the operation time in an unloading process can only be determined and optimized based on a transient analysis.

  2. Key factors for determining groundwater impacts due to leakage from geologic carbon sequestration reservoirs

    DOE Public Access Gateway for Energy & Science Beta (PAGES Beta)

    Carroll, Susan A.; Keating, Elizabeth; Mansoor, Kayyum; Dai, Zhenxue; Sun, Yunwei; Trainor-Guitton, Whitney; Brown, Chris; Bacon, Diana

    2014-09-07

    The National Risk Assessment Partnership (NRAP) is developing a science-based toolset for the analysis of potential impacts to groundwater chemistry from CO2 injection (www.netldoe.gov/nrap). The toolset adopts a stochastic approach in which predictions address uncertainties in shallow groundwater and leakage scenarios. It is derived from detailed physics and chemistry simulation results that are used to train more computationally efficient models, referred to here as reduced-order models (ROMs), for each component system. In particular, these tools can be used to help regulators and operators understand the expected sizes and longevity of plumes in pH, TDS, and dissolved metals that could resultmore » from a leakage of brine and/or CO2 from a storage reservoir into aquifers. This information can inform, for example, decisions on monitoring strategies that are both effective and efficient. We have used this approach to develop predictive reduced-order models for two common types of reservoirs, but the approach could be used to develop a model for a specific aquifer or other common types of aquifers. In this paper we describe potential impacts to groundwater quality due to CO2 and brine leakage, discuss an approach to calculate thresholds under which no impact to groundwater occurs, describe the time scale for impact on groundwater, and discuss the probability of detecting a groundwater plume should leakage occur. To facilitate this, multi-phase flow and reactive transport simulations and emulations were developed for two classes of aquifers, considering uncertainty in leakage source terms and aquifer hydrogeology. We targeted an unconfined fractured carbonate aquifer based on the Edwards aquifer in Texas and a confined alluvium aquifer based on the High Plains Aquifer in Kansas, which share characteristics typical of many drinking water aquifers in the United States. The hypothetical leakage scenarios centered on the notion that wellbores are the most likely conduits for brine and CO2 leaks. Leakage uncertainty was based on hypothetical injection of CO2 for 50 years at a rate of 5 million tons per year into a depleted oil/gas reservoir with high permeability and, one or more wells provided leakage pathways from the storage reservoir to the overlying aquifer. This scenario corresponds to a storage site with historical oil/gas production and some poorly completed legacy wells that went undetected through site evaluation, operations, and post-closure. For the aquifer systems and leakage scenarios studied here, CO2 and brine leakage are likely to drive pH below and increase total dissolved solids (TDS) above the “no-impact thresholds;” and the subsequent plumes, although small, are likely to persist for long periods of time in the absence of remediation. In these scenarios, however, risk to human health may not be significant for two reasons. First, our simulated plume volumes are much smaller than the average inter-well spacing for these representative aquifers, so the impacted groundwater would be unlikely to be pumped for drinking water. Second, even within the impacted plume volumes little water exceeds the primary maximum contamination levels.« less

  3. Improving Geologic and Engineering Models of Midcontinent Fracture and Karst-Modified Reservoirs Using New 3-D Seismic Attributes

    SciTech Connect (OSTI)

    Susan Nissen; Saibal Bhattacharya; W. Lynn Watney; John Doveton

    2009-03-31

    Our project goal was to develop innovative seismic-based workflows for the incremental recovery of oil from karst-modified reservoirs within the onshore continental United States. Specific project objectives were: (1) to calibrate new multi-trace seismic attributes (volumetric curvature, in particular) for improved imaging of karst-modified reservoirs, (2) to develop attribute-based, cost-effective workflows to better characterize karst-modified carbonate reservoirs and fracture systems, and (3) to improve accuracy and predictiveness of resulting geomodels and reservoir simulations. In order to develop our workflows and validate our techniques, we conducted integrated studies of five karst-modified reservoirs in west Texas, Colorado, and Kansas. Our studies show that 3-D seismic volumetric curvature attributes have the ability to re-veal previously unknown features or provide enhanced visibility of karst and fracture features compared with other seismic analysis methods. Using these attributes, we recognize collapse features, solution-enlarged fractures, and geomorphologies that appear to be related to mature, cockpit landscapes. In four of our reservoir studies, volumetric curvature attributes appear to delineate reservoir compartment boundaries that impact production. The presence of these compartment boundaries was corroborated by reservoir simulations in two of the study areas. Based on our study results, we conclude that volumetric curvature attributes are valuable tools for mapping compartment boundaries in fracture- and karst-modified reservoirs, and we propose a best practices workflow for incorporating these attributes into reservoir characterization. When properly calibrated with geological and production data, these attributes can be used to predict the locations and sizes of undrained reservoir compartments. Technology transfer of our project work has been accomplished through presentations at professional society meetings, peer-reviewed publications, Kansas Geological Survey Open-file reports, Master's theses, and postings on the project website: http://www.kgs.ku.edu/SEISKARST.

  4. APPLICATION OF RESERVOIR CHARACTERIZATION AND ADVANCED TECHNOLOGY TO IMPROVE RECOVERY AND ECONOMICS IN A LOWER QUALITY SHALLOW SHELF SAN ANDRES RESERVOIR

    SciTech Connect (OSTI)

    Tom Beebe

    2003-05-05

    The OXY-operated Class 2 Project at West Welch is designed to demonstrate how the use of advanced technology can improve the economics of miscible CO{sub 2} injection projects in lower quality Shallow Shelf Carbonate reservoirs. The research and design phase (Budget Period 1) primarily involved advanced reservoir characterization. The current demonstration phase (Budget Period 2) is the implementation of the reservoir management plan for an optimum miscible CO{sub 2} flood design based on the reservoir characterization. Although Budget Period 1 for the Project officially ended 12/31/96, reservoir characterization and simulation work continued during the Budget Period 2. During the seventh annual reporting period (8/3/00-8/2/01) covered by this report, work continued on interpretation of the interwell seismic data to create porosity and permeability profiles which were distributed into the reservoir geostatistically. The initial interwell seismic CO{sub 2} monitor survey was conducted and the acquired data processed and interpretation started. Only limited well work and facility construction were conducted in the project area. The CO{sub 2} injection initiated in October 1997 was continued, although the operator had to modify the operating plan in response to low injection rates, well performance and changes in CO{sub 2} supply. CO{sub 2} injection was focused in a smaller area to increase the reservoir processing rate. By the end of the reporting period three producers had shown sustained oil rate increases and six wells had experienced gas (CO{sub 2}) breakthrough.

  5. APPLICATION OF RESERVOIR CHARACTERIZATION AND ADVANCED TECHNOLOGY TO IMPROVE RECOVERY AND ECONOMICS IN A LOWER QUALITY SHALLOW SHELF SAN ANDRES RESERVOIR

    SciTech Connect (OSTI)

    T. Scott Hickman; James J. Justice

    2002-01-09

    The OXY-operated Class 2 Project at West Welch is designed to demonstrate how the use of advanced technology can improve the economics of miscible CO{sub 2} injection projects in lower quality Shallow Shelf Carbonate reservoirs. The research and design phase (Budget Period 1) primarily involved advanced reservoir characterization. The current demonstration phase (Budget Period 2) is the implementation of the reservoir management plan for an optimum miscible CO{sub 2} flood design based on the reservoir characterization. Although Budget Period 1 for the Project officially ended 12/31/96, reservoir characterization and simulation work continued during the Budget Period 2. During the fifth and sixth annual reporting periods (8/3/98-8/2/00) covered by this report, work continued on interpretation of the cross well seismic data to create porosity and permeability profiles which were distributed into the reservoir geostatistically. The initial interwell seismic CO{sub 2} monitor survey was conducted, the acquired data processed and interpretation started. Only limited well work and facility construction was conducted in the project area. The CO{sub 2} injection initiated in October 1997 was continued, although the operator had to modify the operating plan in response to low injection rates, well performance and changes in CO{sub 2} supply. CO{sub 2} injection was focused in a smaller area to increase the reservoir processing rate. By the end of the reporting period three producers had shown sustained oil rate increases and ten wells had experienced gas (CO{sub 2}) breakthrough.

  6. Storage capacity in hot dry rock reservoirs

    DOE Patents [OSTI]

    Brown, D.W.

    1997-11-11

    A method is described for extracting thermal energy, in a cyclic manner, from geologic strata which may be termed hot dry rock. A reservoir comprised of hot fractured rock is established and water or other liquid is passed through the reservoir. The water is heated by the hot rock, recovered from the reservoir, cooled by extraction of heat by means of heat exchange apparatus on the surface, and then re-injected into the reservoir to be heated again. Water is added to the reservoir by means of an injection well and recovered from the reservoir by means of a production well. Water is continuously provided to the reservoir and continuously withdrawn from the reservoir at two different flow rates, a base rate and a peak rate. Increasing water flow from the base rate to the peak rate is accomplished by rapidly decreasing backpressure at the outlet of the production well in order to meet periodic needs for amounts of thermal energy greater than a baseload amount, such as to generate additional electric power to meet peak demands. The rate of flow of water provided to the hot dry rock reservoir is maintained at a value effective to prevent depletion of the liquid inventory of the reservoir. 4 figs.

  7. Calif--Los Angeles Basin Onshore Crude Oil Reserves in Nonproducing

    U.S. Energy Information Administration (EIA) Indexed Site

    Reservoirs (Million Barrels) Crude Oil Reserves in Nonproducing Reservoirs (Million Barrels) Calif--Los Angeles Basin Onshore Crude Oil Reserves in Nonproducing Reservoirs (Million Barrels) Decade Year-0 Year-1 Year-2 Year-3 Year-4 Year-5 Year-6 Year-7 Year-8 Year-9 1990's NA NA 53 56 2000's 68 97 122 117 63 112 149 98 31 29 2010's 66 69 55 60 45 - = No Data Reported; -- = Not Applicable; NA = Not Available; W = Withheld to avoid disclosure of individual company data. Release Date:

  8. Calif--San Joaquin Basin Onshore Crude Oil Reserves in Nonproducing

    U.S. Energy Information Administration (EIA) Indexed Site

    Reservoirs (Million Barrels) Crude Oil Reserves in Nonproducing Reservoirs (Million Barrels) Calif--San Joaquin Basin Onshore Crude Oil Reserves in Nonproducing Reservoirs (Million Barrels) Decade Year-0 Year-1 Year-2 Year-3 Year-4 Year-5 Year-6 Year-7 Year-8 Year-9 1990's NA NA 740 321 2000's 234 233 111 110 158 238 228 168 117 146 2010's 210 163 226 214 216 - = No Data Reported; -- = Not Applicable; NA = Not Available; W = Withheld to avoid disclosure of individual company data. Release

  9. Skimming' a reservoir for trash

    SciTech Connect (OSTI)

    Shenman, L.E. )

    1993-02-01

    Several hydropower facilities are using a new technology for removing floating trash in reservoirs. Representatives from the facilities say the boat, called a trashskimmer, is efficient, easy to maneuver, and transportable. Designed by United Marine International, Inc., the pontoon boat features an operators cab that straddles an open hull between the skis of the pontoon, and uses dual propellers to maneuver through the water. The Marineskimmer allows the operator to approach the trash from the water side upstream of the plant. The Tennessee Valley Authority has used the boat since 1990.

  10. Twelfth workshop on geothermal reservoir engineering: Proceedings

    SciTech Connect (OSTI)

    Ramey, H.J. Jr.; Kruger, P.; Miller, F.G.; Horne, R.N.; Brigham, W.E.; Rivera, J.

    1987-01-22

    Preface The Twelfth Workshop on Geothermal Reservoir Engineering was held at Stanford University on January 20-22, 1987. The year ending December 1986 was very difficult for the domestic geothermal industry. Low oil prices caused a sharp drop in geothermal steam prices. We expected to see some effect upon attendance at the Twelfth Workshop. To our surprise, the attendance was up by thirteen from previous years, with one hundred and fifty-seven registered participants. Eight foreign countries were represented: England, France, Iceland, Italy, Japan, Mexico, New Zealand, and Turkey. Despite a worldwide surplus of oil, international geothermal interest and development is growing at a remarkable pace. There were forty-one technical presentations at the Workshop. All of these are published as papers in this Proceedings volume. Seven technical papers not presented at the Workshop are also published; they concern geothermal developments and research in Iceland, Italy, and New Zealand. In addition to these forty-eight technical presentations or papers, the introductory address was given by Henry J. Ramey, Jr. from the Stanford Geothermal Program. The Workshop Banquet speaker was John R. Berg from the Department of Energy. We thank him for sharing with the Workshop participants his thoughts on the expectations of this agency in the role of alternative energy resources, specifically geothermal, within the country???s energy framework. His talk is represented as a paper in the back of this volume. The chairmen of the technical sessions made an important contribution to the workshop. Other than Stanford faculty members they included: M. Gulati, K. Goyal, G.S. Bodvarsson, A.S. Batchelor, H. Dykstra, M.J. Reed, A. Truesdell, J.S. Gudmundsson, and J.R. Counsil. The Workshop was organized by the Stanford Geothermal Program faculty, staff, and students. We would like to thank Jean Cook, Marilyn King, Amy Osugi, Terri Ramey, and Rosalee Benelli for their valued help with the meeting arrangements and preparing the Proceedings. We also owe great thanks to our students who arranged and operated the audio-visual equipment, specially Jim Lovekin. The Twelfth Workshop was supported by the Geothermal Technology Division of the U. S. Department of Energy through Contract Nos. DE-AS03-80SF11459 and DE-AS07- 84ID12529. We deeply appreciate this continued support. January 1987 Henry J. Ramey, Jr. Paul Kruger Roland N. Horne William E. Brigham Frank G. Miller Jesus Rivera

  11. The use of coiled tubing during matrix acidizing of carbonate reservoirs

    SciTech Connect (OSTI)

    Thomas, R.L.; Milne, A.

    1995-10-01

    A laboratory and field study directed at improved well performance of horizontal wells is discussed. During the study, several wells were matrix acidized using bullhead and coiled tubing placement techniques. The study performed in carbonate reservoirs indicates acid placed with coiled tubing diverted with foam provides excellent zone coverage and damage removal. Conventional bullhead techniques do not result in effective damage removal. The study emphasizes the evaluation of the treatment results and the development of improved acidizing techniques. Laboratory simulations of matrix acidizing indicate proper placement techniques are essential. This observation is supported by field data in oil wells completed in carbonate reservoirs. The key to successful damage removal is (1) the placement of acid via coiled tubing and (2) proper diversion. Production logging and well performance data support this claim. The proposed treatment is applicable in both horizontal and vertical wells completed in carbonate reservoirs.

  12. Full Reviews: Reservoir Characterization | Department of Energy

    Broader source: Energy.gov (indexed) [DOE]

    Reservoir Characterization. Three-dimensional Modeling of Fracture Clusters in Geothermal Reservoirs Ahmad Ghassmi, Texas A&M University Project Presentation | Peer Reviewer Comments Use of Geophysical Techniques to Characterize Fluid Flow in a Geothermal Reservoir André Revil, Colorado School of Mines Project Presentation | Peer Reviewer Comments Detection and Characterization of Natural and Induced Fractures for the Development of Enhanced Geothermal Systems M. Nafi Toksoz, Massachusetts

  13. 201202 Reservoir System Modeling Technologies Conference

    Broader source: All U.S. Department of Energy (DOE) Office Webpages (Extended Search)

    Modeling Applied To The Columbia River - PSR Adjoint Modeling Framework for Real-Time Control of Water - Deltares Reservoir Operations Analysis in the Willamette Water 2100...

  14. Precise Gravimetry and Geothermal Reservoir Management | Open...

    Open Energy Info (EERE)

    Precise Gravimetry and Geothermal Reservoir Management Jump to: navigation, search OpenEI Reference LibraryAdd to library Conference Paper: Precise Gravimetry and Geothermal...

  15. Analysis of Geothermal Reservoir Stimulation using Geomechanics...

    Office of Energy Efficiency and Renewable Energy (EERE) Indexed Site

    Geomechanics-Based Stochastic Analysis of Injection-Induced Seismicity Analysis of Geothermal Reservoir Stimulation using Geomechanics-Based Stochastic Analysis of ...

  16. Analysis of Geothermal Reservoir Stimulation Using Geomechanics...

    Office of Energy Efficiency and Renewable Energy (EERE) Indexed Site

    Analysis of Geothermal Reservoir Stimulation Using Geomechanics-based Stochastic Analysis of Injection-induced Seismicity; 2010 Geothermal Technology Program Peer Review Report ...

  17. Storage capacity in hot dry rock reservoirs

    DOE Patents [OSTI]

    Brown, Donald W.

    1997-01-01

    A method of extracting thermal energy, in a cyclic manner, from geologic strata which may be termed hot dry rock. A reservoir comprised of hot fractured rock is established and water or other liquid is passed through the reservoir. The water is heated by the hot rock, recovered from the reservoir, cooled by extraction of heat by means of heat exchange apparatus on the surface, and then re-injected into the reservoir to be heated again. Water is added to the reservoir by means of an injection well and recovered from the reservoir by means of a production well. Water is continuously provided to the reservoir and continuously withdrawn from the reservoir at two different flow rates, a base rate and a peak rate. Increasing water flow from the base rate to the peak rate is accomplished by rapidly decreasing backpressure at the outlet of the production well in order to meet periodic needs for amounts of thermal energy greater than a baseload amount, such as to generate additional electric power to meet peak demands. The rate of flow of water provided to the hot dry rock reservoir is maintained at a value effective to prevent depletion of the liquid

  18. Hydrothermal Convection Systems with Reservoir Temperatures greater...

    Open Energy Info (EERE)

    Systems with Reservoir Temperatures greater than or equal to 90 degrees C Authors Brook, Mariner, Mabey, Swanson, Guffanti and Muffler Published Journal Assessment of...

  19. Geothermometry At Blackfoot Reservoir Area (Hutsinpiller & Parry...

    Open Energy Info (EERE)

    Activity Details Location Blackfoot Reservoir Area Exploration Technique Geothermometry Activity Date Usefulness useful DOE-funding Unknown References Amy Hutsinpiller, W. T....

  20. Modeling of Geothermal Reservoirs: Fundamental Processes, Computer...

    Open Energy Info (EERE)

    of Geothermal Reservoirs: Fundamental Processes, Computer Simulation and Field Applications Jump to: navigation, search OpenEI Reference LibraryAdd to library Journal Article:...

  1. Characterization of Fractures in Geothermal Reservoirs Using...

    Open Energy Info (EERE)

    Abstract The optimal design of production in fractured geothermal reservoirs requires knowledge of the resource's connectivity, therefore making fracture characterization highly...

  2. Evaluation Of Chemical Geothermometers For Calculating Reservoir...

    Open Energy Info (EERE)

    Geothermometers For Calculating Reservoir Temperatures At Nevada Geothermal Power Plants Jump to: navigation, search OpenEI Reference LibraryAdd to library Conference Paper:...

  3. International reservoir operations agreement helps NW fish &...

    Broader source: All U.S. Department of Energy (DOE) Office Webpages (Extended Search)

    or 503-230-5131 International reservoir operations agreement helps Northwest fish and power Portland, Ore. - The Bonneville Power Administration and the British Columbia...

  4. Geothermal reservoirs in hydrothermal convection systems

    SciTech Connect (OSTI)

    Sorey, M.L.

    1982-01-01

    Geothermal reservoirs commonly exist in hydrothermal convection systems involving fluid circulation downward in areas of recharge and upwards in areas of discharge. Because such reservoirs are not isolated from their surroundings, the nature of thermal and hydrologic connections with the rest of the system may have significant effects on the natural state of the reservoir and on its response to development. Conditions observed at numerous developed and undeveloped geothermal fields are discussed with respect to a basic model of the discharge portion of an active hydrothermal convection system. Effects of reservoir development on surficial discharge of thermal fluid are also delineated.

  5. Geochemistry and habitat of oils in Italy

    SciTech Connect (OSTI)

    Novelli, L.; Mattavelli, L.

    1988-02-01

    Most of the onshore and offshore oil occurrences found in Italy have been systematically analyzed by different techniques, i.e., capillary gas chromatography, biological markers, and stable isotopes composition. On the basis of the above analyses, ten different groups of oil have been identified and geographically located. Subsequently, the influence of the various geological settings on generation and migration of these different groups of oils was investigated and is discussed here. In a foredeep regime, the remarkably fast heating rates, due to the rapid burial during late Tertiary, caused a rapid generation of oil mainly in the Triassic carbonate source rocks. Such generation, combined with the high over-burden pressure and a contemporaneous development of an intense tectonic compression, resulted in the expulsion of immature, heavy oils. Examples of this are evident in the central Adriatic Sea, southern Italy, and southeastern Sicily. Due to its complex geological and tectonic history, the Alpine-Apennine chain behaved differently with regard to oil generation and migration in different areas. In fact, the high temperatures reached by the Mesozoic source rocks underneath a stack of allochthonous thrust sheets and the insulating thermal blanket effect exerted by the same sheets on other younger source rocks above gave rise to generally light oils. Furthermore, in this unique geological setting, the most external thrust sheets locally acted as reservoirs of the foredeep regime. Foreland sequences acted as both reservoirs of the foredeep oils and as generative kitchens of liquid hydrocarbons if suitable source rocks were present and adequate burial was reached.

  6. Reservoir characterization and performance predictions for the E.N. Woods lease

    SciTech Connect (OSTI)

    Aka-Milan, Francis A.

    2000-07-07

    The task of this work was to evaluate the past performance of the E.N. WOODS Unit and to forecast its future economic performance by taking into consideration the geology, petrophysics and production history of the reservoir. The Decline Curve Analysis feature of the Appraisal of Petroleum Properties including Taxation Systems (EDAPT) software along with the Production Management Systems (PMS) software were used to evaluate the original volume of hydrocarbon in place and estimate the reserve. The Black Oil Simulator (BOAST II) was then used to model the waterflooding operation and estimate the incremental oil production attributable to the water injection. BOAST II was also used to predict future performance of the reservoir.

  7. Considering Cumulative Effects Under the National Environmental...

    Energy Savers [EERE]

    Act Considering Cumulative Effects Under the National Environmental Policy Act This handbook presents the results of research and consultations by the Council on Environmental...

  8. Considering Cumulative Effects Under the National Environmental...

    Office of Energy Efficiency and Renewable Energy (EERE) Indexed Site

    Considering Cumulative Effects Under the National Environmental Policy Act (CEQ, 1997) This handbook presents the results of research and consultations by the Council on ...

  9. Activities of the Oil Implementation Task Force, December 1990--February 1991; Contracts for field projects and supporting research on enhanced oil recovery, April--June 1990

    SciTech Connect (OSTI)

    Tiedemann, H.A. )

    1991-03-01

    The Oil Implementation Task Force was appointed to implement the US DOE's new oil research program directed toward increasing domestic oil production by expanded research on near- or mid-term enhanced oil recovery methods. An added priority is to preserve access to reservoirs that have the largest potential for oil recovery, but that are threatened by the large number of wells abandoned each year. This report describes the progress of research activities in the following areas: chemical flooding; gas displacement; thermal recovery; resource assessment; microbial technology; geoscience technology; and environmental technology. (CK)

  10. OIl Speculation

    Annual Energy Outlook [U.S. Energy Information Administration (EIA)]

    of investor flows and financial market conditions on returns in crude-oil futures markets. ... for returns in US and emerging-economy stock markets, a measure of the balance-sheet ...

  11. Exploration model for shallow Silurian (Kankakee) carbonate reservoirs in western Illinois

    SciTech Connect (OSTI)

    Crockett, J.E.; Seyler, B.J.; Whitaker, S.

    1987-09-01

    Reservoirs in shallow (600-650 ft deep) basal Silurian Kankakee carbonates at Buckhorn consolidated, Siloam, and Kellerville oil fields in western Illinois have produced nearly 2 million bbl of oil, but were developed essentially by random drilling. A new exploration model that combines lithologic studies and isopach mapping has been developed at the Illinois State Geological Survey. Isopach mapping of Silurian and Devonian rocks between an organic facies in the Mississippian-Devonian New Albany Shale and the top of the Ordovician Maquoketa Shale reveals thickened sequences that coincide with most of the oil fields. These thickened intervals apparently reflect subtle paleovalleys eroded into the Maquoketa shale during the Ordovician-Silurian hiatus. During the initial Silurian marine transgression, these paleovalleys at the base of the Kankakee were filled with carbonates to form the thickened sequences. Differential erosion at the top of the Kankakee does not satisfactorily explain the locally thickened sequences in the Kankakee. Lithologic studies suggest that subsurface fluid flows concentrated along these paleovalleys contributed to subsequent diagenesis of valleyfill carbonates. Diagenetic alteration of these carbonates resulted in development of basal Kankakee reservoirs within the paleovalleys. This concept of Kankakee reservoirs occurring within paleovalleys at the Ordovician-Silurian unconformity is a new exploration model that can aid in the search for similar traps in western Illinois.

  12. Oil and Gas Lease Equipment and Operating Costs 1994 Through 2009

    Gasoline and Diesel Fuel Update (EIA)

    Oil and Gas Field Code Master List With Data for 2015 | Release Date: February 24, 2016 | Next Release Date: February 2017 Previous Issues Year: 2015 2014 2013 2012 2011 2010 2009 2008 2007 2006 2005 2004 2003 2002 2001 2000 1998 1997 1996 1995 Go Comprehensive listing of U.S. oil and gas field names. Oil and Gas Field Code Master List 2015 Definition of a Field A field is defined as "an area consisting of a single reservoir or multiple reservoirs all grouped on, or related to, the same

  13. CO2 is dominant greenhouse gas emitted from six hydropower reservoirs in southeastern United States during peak summer emissions

    DOE Public Access Gateway for Energy & Science Beta (PAGES Beta)

    Bevelhimer, Mark S.; Stewart, Aurthur J.; Fortner, Allison M.; Phillips, Jana Randolph; Mosher, Jennifer J.

    2016-01-06

    During August-September 2012, we sampled six hydropower reservoirs in southeastern United States. for CO2 and CH4 emissions via three pathways: diffusive emissions from water surface; ebullition in the water column; and losses from dam tailwaters during power generation. Average total emission rates of CO2 for the six reservoirs ranged from 1,127 to 2,051 mg m-2 d-1, which is low to moderate compared to CO2 emissions rates reported for tropical hydropower reservoirs and boreal ponds and lakes, and similar to rates reported for other temperate reservoirs. Similar average rates for CH4 were also relatively low, ranging from 5 to 83 mgmore » m-2 d-1. On a whole-reservoir basis, total emissions of CO2 ranged nearly 10-fold, from ~51,000 kg per day for Fontana to ~486,000 kg per day for Guntersville, and total emissions of CH4 ranged nearly 20-fold, from ~5 kg per day for Fontana to ~83 kg per day for Allatoona. Emissions through the tailwater pathway varied among reservoirs, comprising from 20 to 50% of total CO2 emissions and 0 to 90% of CH4 emissions, depending on the reservoir. Furthermore, several explanatory factors related to reservoir morphology and water quality were considered for observed differences among reservoirs.« less

  14. Oil and gas resources in the West Siberian Basin, Russia

    SciTech Connect (OSTI)

    1997-12-01

    The primary objective of this study is to assess the oil and gas potential of the West Siberian Basin of Russia. The study does not analyze the costs or technology necessary to achieve the estimates of the ultimate recoverable oil and gas. This study uses reservoir data to estimate recoverable oil and gas quantities which were aggregated to the field level. Field totals were summed to a basin total for discovered fields. An estimate of undiscovered oil and gas, from work of the US Geological Survey (USGS), was added to give a total basin resource volume. Recent production decline points out Russia`s need to continue development of its discovered recoverable oil and gas. Continued exploration is required to discover additional oil and gas that remains undiscovered in the basin.

  15. Economics of Developing Hot Stratigraphic Reservoirs

    SciTech Connect (OSTI)

    Greg Mines; Hillary Hanson; Rick Allis; Joseph Moore

    2014-09-01

    Stratigraphic geothermal reservoirs at 3 – 4 km depth in high heat-flow basins are capable of sustaining 100 MW-scale power plants at about 10 c/kWh. This paper examines the impacts on the levelized cost of electricity (LCOE) of reservoir depth and temperature, reservoir productivity, and drillhole/casing options. For a reservoir at 3 km depth with a moderate productivity index by hydrothermal reservoir standards (about 50 L/s/MPa, 5.6 gpm/psi), an LCOE of 10c/kWh requires the reservoir to be at about 200°C. This is the upper temperature limit for pumps. The calculations assume standard hydrothermal drilling costs, with the production interval completed with a 7 inch liner in an 8.5 inch hole. If a reservoir at 4 km depth has excellent permeability characteristics with a productivity index of 100 L/s/MPa (11.3 gpm/psi), then the LCOE is about 11 c/kWh assuming the temperature decline rate with development is not excessive (< 1%/y, with first thermal breakthrough delayed by about 10 years). Completing wells with modest horizontal legs (e.g. several hundred meters) may be important for improving well productivity because of the naturally high, sub-horizontal permeability in this type of reservoir. Reducing the injector/producer well ratio may also be cost-effective if the injectors are drilled as larger holes.

  16. Water resources review: Wheeler Reservoir, 1990

    SciTech Connect (OSTI)

    Wallus, R.; Cox, J.P.

    1990-09-01

    Protection and enhancement of water quality is essential for attaining the full complement of beneficial uses of TVA reservoirs. The responsibility for improving and protecting TVA reservoir water quality is shared by various federal, state, and local agencies, as well as the thousands of corporations and property owners whose individual decisions affect water quality. TVA's role in this shared responsibility includes collecting and evaluating water resources data, disseminating water resources information, and acting as a catalyst to bring together agencies and individuals that have a responsibility or vested interest in correcting problems that have been identified. This report is one in a series of status reports that will be prepared for each of TVA's reservoirs. The purpose of this status report is to provide an up-to-date overview of the characteristics and conditions of Wheeler Reservoir, including: reservoir purposes and operation; physical characteristics of the reservoir and the watershed; water quality conditions: aquatic biological conditions: designated, actual, and potential uses of the reservoir and impairments of those uses; ongoing or planned reservoir management activities. Information and data presented here are form the most recent reports, publications, and original data available. 21 refs., 8 figs., 29 tabs.

  17. Some mismatches occurred when simulating fractured reservoirs as homogeneous porous media

    SciTech Connect (OSTI)

    Mario Cesar Suarez Arriaga; Fernando Samaniego V.; Fernando Rodriguez

    1996-01-24

    The understanding of transport processes that occur in naturally fractured geothermal systems is far from being complete. Often, evaluation and numerical simulations of fractured geothermal reservoirs, are carried out by assuming equivalent porous media and homogeneous petrophysical properties within big matrix blocks. The purpose of this paper, is to present a comparison between results obtained from numerical studies of a naturally fractured reservoir treated as a simple porous medium and the simulation of some real aspects of the fractured reservoir. A general conclusion outlines the great practical importance of considering even approximately, the true nature of such systems. Our results show that the homogeneous simplified evaluation of the energy resource in a fractured system, could result in unrealistic estimates of the reservoir capacity to generate electricity.

  18. INTELLIGENT COMPUTING SYSTEM FOR RESERVOIR ANALYSIS AND RISK ASSESSMENT OF THE RED RIVER FORMATION

    SciTech Connect (OSTI)

    Kenneth D. Luff

    2002-09-30

    Integrated software has been written that comprises the tool kit for the Intelligent Computing System (ICS). Luff Exploration Company is applying these tools for analysis of carbonate reservoirs in the southern Williston Basin. The integrated software programs are designed to be used by small team consisting of an engineer, geologist and geophysicist. The software tools are flexible and robust, allowing application in many environments for hydrocarbon reservoirs. Keystone elements of the software tools include clustering and neural-network techniques. The tools are used to transform seismic attribute data to reservoir characteristics such as storage (phi-h), probable oil-water contacts, structural depths and structural growth history. When these reservoir characteristics are combined with neural network or fuzzy logic solvers, they can provide a more complete description of the reservoir. This leads to better estimates of hydrocarbons in place, areal limits and potential for infill or step-out drilling. These tools were developed and tested using seismic, geologic and well data from the Red River Play in Bowman County, North Dakota and Harding County, South Dakota. The geologic setting for the Red River Formation is shallow-shelf carbonate at a depth from 8000 to 10,000 ft.

  19. ,"Total Fuel Oil Expenditures

    U.S. Energy Information Administration (EIA) Indexed Site

    . Fuel Oil Expenditures by Census Region for Non-Mall Buildings, 2003" ,"Total Fuel Oil Expenditures (million dollars)",,,,"Fuel Oil Expenditures (dollars)" ,,,,,"per...

  20. ,"Total Fuel Oil Consumption

    U.S. Energy Information Administration (EIA) Indexed Site

    0. Fuel Oil Consumption (gallons) and Energy Intensities by End Use for Non-Mall Buildings, 2003" ,"Total Fuel Oil Consumption (million gallons)",,,,,"Fuel Oil Energy Intensity...

  1. ,"Total Fuel Oil Expenditures

    U.S. Energy Information Administration (EIA) Indexed Site

    4. Fuel Oil Expenditures by Census Region, 1999" ,"Total Fuel Oil Expenditures (million dollars)",,,,"Fuel Oil Expenditures (dollars)" ,,,,,"per Gallon",,,,"per Square Foot"...

  2. ,"Total Fuel Oil Expenditures

    U.S. Energy Information Administration (EIA) Indexed Site

    A. Fuel Oil Expenditures by Census Region for All Buildings, 2003" ,"Total Fuel Oil Expenditures (million dollars)",,,,"Fuel Oil Expenditures (dollars)" ,,,,,"per Gallon",,,,"per...

  3. ,"Total Fuel Oil Consumption

    U.S. Energy Information Administration (EIA) Indexed Site

    A. Fuel Oil Consumption (gallons) and Energy Intensities by End Use for All Buildings, 2003" ,"Total Fuel Oil Consumption (million gallons)",,,,,"Fuel Oil Energy Intensity...

  4. An integrated study of the Grayburg/San Andres reservoir, Foster and South Cowden fields, Ector County, Texas, Class II

    SciTech Connect (OSTI)

    Trentham, DGS, Robert C.; Robinson, M.S., William C.; Wider, Kevin; Weinbrandt, Ph.D.,PE, Richard

    2000-04-14

    A project to recover economic amounts of oil from a very mature oil field is being conducted by Laguna Petroleum Corporation of Midland, Texas, with partial funding from a U. S. Department of Energy (DOE) grant to study shallow carbonate rock reservoirs. The objectives of the project are to use modern engineering methods to optimize oil field management and to use geological and geophysical data to recover untapped potential within the petroleum reservoirs. The integration of data and techniques from these disciplines has yielded results greater than those achievable without their cooperation. The cost of successfully accomplishing these goals is to be low enough for even small independent operators to afford. This article is a report describing accomplishments for the fiscal year 1998-1999.

  5. Intricate Puzzle of Oil and Gas Reserves Growth

    Reports and Publications (EIA)

    1997-01-01

    This article begins with a background discussion of the methods used to estimate proved oil and gas reserves and ultimate recovery, which is followed by a discussion of the factors that affect the ultimate recovery estimates of a field or reservoir.

  6. EIA - Natural Gas Pipeline Network - Depleted Reservoir Storage

    U.S. Energy Information Administration (EIA) Indexed Site

    Configuration Depleted Reservoir Storage Configuration About U.S. Natural Gas Pipelines - Transporting Natural Gas based on data through 2007/2008 with selected updates Depleted Production Reservoir Underground Natural Gas Storage Well Configuration Depleted Production Reservoir Storage

  7. Wireless technology collects real-time information from oil and gas wells

    Broader source: All U.S. Department of Energy (DOE) Office Webpages (Extended Search)

    Wireless technology collects real-time information from oil and gas wells Wireless technology collects real-time information from oil and gas wells The patented system delivers continuous electromagnetic data on the reservoir conditions, enabling economical and effective monitoring and analysis. April 3, 2012 One of several active projects, LANL and Chevron co-developed INFICOMM(tm), a wireless technology used to collect real-time temperature and pressure information from sensors in oil and gas

  8. Reservoir geology of Landslide field, southern San Joaquin basin, California

    SciTech Connect (OSTI)

    Carr, T.R.; Tucker, R.D.; Singleton, M.T. )

    1991-02-01

    The Landslide field, which is located on the southern margin of the San Joaquin basin, was discovered in 1985 and consists of 13 producers and six injectors. Cumulative production as of mid-1990 was approximately 10 million bbl of oil with an average daily production of 4700 BOPD. Production is from a series of late Miocene turbidite sands (Stevens Sand) that were deposited as a small constructional submarine fan (less than 2 mi in diameter). Based on interpretation of wireline logs and engineering data, deposition of the fan and of individual lobes within the fan was strongly influenced by preexisting paleotopography and small syndepositional slump features. Based on mapping of individual depositional units and stratigraphic dipmeter analysis, transport direction of the sand was to the north-north across these paleotopographic breaks in slope. Dipmeter data and pressure data from individual sands are especially useful for recognition and mapping of individual flow units between well bores. Detailed engineering, geophysical and geological studies have increased our understanding of the dimensions, continuity, geometry, and inherent reservoir properties of the individual flow units within the reservoir. Based on the results of these studies a series of water isolation workovers and extension wells were proposed and successfully undertaken. This work has increased recoverable reserves and arrested the rapid production decline.

  9. Application of reservoir characterization and advanced technology to improve recovery and economics in a lower quality shallow shelf carbonate reservoir. [Quarterly report], October 1, 1995--December 31, 1995

    SciTech Connect (OSTI)

    Taylor, A.R.

    1996-01-01

    West Welch Unit is one of four large waterflood units in the Welch Field in the northwestern portion of Dawson County, TX. This field was discovered early 1940`s and produces oil under a solution gas drive mechanism from the Sand Adres formation at {approx}4800 ft. This field has been under waterflood for 30 yr and a significant portion has been infill drilled on 20-ac density. A 1982-86 CO{sub 2} injection project in the offsetting South Welch Unit yielded positive results. Recent installation of a CO{sub 2} pipeline near the field allowed phased development of a miscible CO{sub 2} injection project at the South Welch Unit. Reservoir quality is poorer at West Welch Unit due to relative position to sea level during deposition, and this unit is ideal for demonstrating methods for enhancing economics of IOR projects in lower quality SSC (shallow shelf carbonate) reservoirs. This Class 2 project concentrates on the efficient design of a miscible CO{sub 2} project based on detailed reservoir characterization. During the quarter, progress was made on petrophysical analysis and tomography processing. The geologic model is dependent on these, and the actual reservoir simulation cannot start until the geologic model is complete, although all the preliminary simulation work is being done.

  10. Gupco's experience in treating Gulf of Suez seawater for waterflooding the El Morgan oil field

    SciTech Connect (OSTI)

    El-Hattab, M.I.

    1982-07-01

    Pressure maintenance by waterflooding in some reservoirs may be considered essential for satisfactory oil recovery. The main objective of waterflooding is to place water into a rock formation at both the desired rate and pressure with minimal expense and trouble. This objective, however, cannot be achieved unless this water has certain characteristics. The water, therefore, should be treated and conditioned before injection. This study addresses the treatment phases adopted to improve seawater quality before injection, and to control problems associated with untreated seawater. Also discussed are GUPCO'S (Gulf of Suez Petroleum Co.) experience in seawaterfloods, problems encountered, and corrective actions taken to overcome these problems. The chemical treatment programs adopted are presented along with final conclusions and recommendations that can be applied to similar floods in Egypt with (Gulf of Suez) GOS. 47 refs.

  11. Advanced reservoir characterization and evaluation of CO{sub 2} gravity drainage in the naturally fractured Spraberry Trend Area. Annual report, September 1, 1995--August 31, 1996

    SciTech Connect (OSTI)

    Schechter, D.S.

    1997-12-01

    The overall goal of this project is to assess the economic feasibility of CO{sub 2} flooding in the naturally fractured Spraberry Trend Area in West Texas. This objective is being accomplished by conducting research in four areas: (1) extensive characterization of the reservoirs, (2) experimental studies of crude oil/brine/rock (COBR) interaction in the reservoirs, (3) analytical and numerical simulation of Spraberry reservoirs, and, (4) experimental investigations on CO{sub 2} gravity drainage in Spraberry whole cores. This report provides results of the first year of the five-year project for each of the four areas.

  12. Application of advanced reservoir characterization, simulation, and production optimization strategies to maximize recovery in slope and basin clastic reservoirs, west Texas (Delaware Basin). Annual progress report, March 31, 1995--March 31, 1996

    SciTech Connect (OSTI)

    Dutton, S.P.; Hovorka, S.D.; Cole, A.G.

    1996-08-01

    The objective of this Class III project is to demonstrate that detailed reservoir characterization of clastic reservoirs in basinal sandstones of the Delaware Mountain Group in the Delaware Basin of West Texas and New Mexico is a cost-effective way to recover more of the original oil in place by strategic infill-well placement and geologically based field development. Reservoirs in the Delaware Mountain Group have low producibility (average recovery <14 percent of the original oil in place) because of a high degree of vertical and lateral heterogeneity caused by depositional processes and post-depositional diagenetic modification. Detailed correlations of the Ramsey sandstone reservoirs in Geraldine Ford field suggest that lateral sandstone continuity is less than interpreted by previous studies. The degree of lateral heterogeneity in the reservoir sandstones suggests that they were deposited by eolian-derived turbidites. According to the eolian-derived turbidite model, sand dunes migrated across the exposed shelf to the shelf break during sea-level lowstands and provided well sorted sand for turbidity currents or grain flows into the deep basin.

  13. Property:USGSMeanReservoirTemp | Open Energy Information

    Open Energy Info (EERE)

    to: navigation, search Property Name USGSMeanReservoirTemp Property Type Temperature Description Mean estimated reservoir temperature at location based on the USGS 2008 Geothermal...

  14. Sustainability of Shear-Induced Permeability for EGS Reservoirs...

    Office of Energy Efficiency and Renewable Energy (EERE) Indexed Site

    Sustainability of Shear-Induced Permeability for EGS Reservoirs A Laboratory Study Sustainability of Shear-Induced Permeability for EGS Reservoirs A Laboratory Study ...

  15. EIA - Natural Gas Pipeline Network - Depleted Reservoir Storage...

    U.S. Energy Information Administration (EIA) Indexed Site

    Depleted Reservoir Storage Configuration About U.S. Natural Gas Pipelines - Transporting ... Depleted Production Reservoir Underground Natural Gas Storage Well Configuration Depleted ...

  16. EIA - Natural Gas Pipeline Network - Salt Cavern Storage Reservoir...

    U.S. Energy Information Administration (EIA) Indexed Site

    Salt Cavern Underground Natural Gas Storage Reservoir Configuration Salt Cavern Underground Natural Gas Storage Reservoir Configuration Source: PB Energy Storage Services Inc.

  17. EIA - Natural Gas Pipeline Network - Aquifer Storage Reservoir...

    U.S. Energy Information Administration (EIA) Indexed Site

    Aquifer Storage Reservoir Configuration About U.S. Natural Gas Pipelines - Transporting ... Aquifer Underground Natural Gas Storage Reservoir Configuration Aquifer Underground ...

  18. Dispersed Fluid Flow in Fractured Reservoirs- an Analysis of...

    Open Energy Info (EERE)

    Reservoirs- an Analysis of Tracer-Determined Residence Time Distributions Abstract A methodology for analyzing the internal flow characteristics of a fractured geothermal reservoir...

  19. Update on the Raft River Geothermal Reservoir | Open Energy Informatio...

    Open Energy Info (EERE)

    the Raft River Geothermal Reservoir Jump to: navigation, search OpenEI Reference LibraryAdd to library Conference Proceedings: Update on the Raft River Geothermal Reservoir...

  20. IPGT Reservoir Modeling Working Group | Department of Energy

    Office of Energy Efficiency and Renewable Energy (EERE) Indexed Site

    IPGT Reservoir Modeling Working Group Summary of recommendations and geothermal reservoir benchmarking workshop PDF icon gtp2012peerreviewreservoirmodeling.pdf More Documents & ...

  1. Deep Geothermal Reservoir Temperatures in the Eastern Snake River...

    Office of Scientific and Technical Information (OSTI)

    Geothermal Reservoir Temperatures in the Eastern Snake River Plain, Idaho using Multicomponent Geothermometry Citation Details In-Document Search Title: Deep Geothermal Reservoir ...

  2. Flow and Thermal Behavior of an EGS Reservoir - Geothermal Code...

    Office of Scientific and Technical Information (OSTI)

    of an EGS Reservoir - Geothermal Code Comparison Study Citation Details In-Document Search Title: Flow and Thermal Behavior of an EGS Reservoir - Geothermal Code Comparison Study ...

  3. Two-dimensional simulation of the Raft River geothermal reservoir...

    Open Energy Info (EERE)

    of the Raft River geothermal reservoir and wells. (SINDA-3G program) Abstract Computer models describing both the transient reservoir pressure behavior and the time...

  4. Geysers Hi-T Reservoir Geothermal Area | Open Energy Information

    Open Energy Info (EERE)

    Geysers Hi-T Reservoir Geothermal Area Jump to: navigation, search GEOTHERMAL ENERGYGeothermal Home Geysers Hi-T Reservoir Geothermal Area Contents 1 Area Overview 2 History and...

  5. An Updated Conceptual Model Of The Los Humeros Geothermal Reservoir...

    Open Energy Info (EERE)

    Humeros Geothermal Reservoir (Mexico) Abstract An analysis of production and reservoir engineering data of 42 wells from the Los Humeros geothermal field (Mexico) allowed...

  6. Hydroprocessing catalysts for heavy oil and coal

    SciTech Connect (OSTI)

    Satriana, M.J.

    1982-01-01

    Hydroprocessing catalysts, as described in over 230 processes covered in this book, are hydrogenation catalysts used in the upgrading of heavy crudes and coal to products expected to be in great demand as the world's primary oil supplies gradually dwindle. The techniques employed in hydroprocessing result in the removal of contaminants, the transformation of lower grade materials such as heavy crudes to valuable fuels, or the conversion of hydrocarbonaceous solids into gaseous or liquid fuel products. All of these techniques are, of course, carried out in the presence of hydrogen. Some of the brightest energy prospects for the future lie in heavy oil reservoirs and coal reserves. Heavy oils, defined in this book as having gravities of < 20/sup 0/API, are crudes so thick that they are not readily extracted from their reservoirs. However, processing of these crudes is of great importance, because the US resource alone is enormous. The main types of processing catalysts covered in the book are hydrorefining catalysts plus some combinations of the two. Catalysts for the conversion of hydrocarbonaceous materials to gaseous or liquid fuels are also covered. The primary starting material for these conversions is coal, but wood, lignin, oil shale, tar sands, and peat are other possibilities. The final chapter describes the preparation of various catalyst support systems.

  7. Improved recovery from Gulf of Mexico reservoirs. Volume III (of 4): Characterization and simulation of representative resources. Final report, February 14, 1995--October 13, 1996

    SciTech Connect (OSTI)

    Kimbrell, W.C.; Bassiouni, Z.A.; Bourgoyne, A.T.

    1997-01-13

    Significant innovations have been made in seismic processing and reservoir simulation. In addition, significant advances have been made in deviated and horizontal drilling technologies. Effective application of these technologies along with improved integrated resource management methods offer opportunities to significantly increase Gulf of Mexico production, delay platform abandonments, and preserve access to a substantial remaining oil target for both exploratory drilling and advanced recovery processes. In an effort to illustrate the impact that these new technologies and sources of information can have upon the estimates of recoverable oil in the Gulf of Mexico, additional and detailed data was collected for two previously studied reservoirs: a South March Island reservoir operated by Taylor Energy and Gulf of Mexico reservoir operated by Mobil, whose exact location has been blind-coded at their request, and an additional third representative reservoir in the Gulf of Mexico, the KEKF-1 reservoir in West Delta Block 84 Field. The new data includes reprocessed 2-D seismic data, newly acquired 3-D data, fluid data, fluid samples, pressure data, well test data, well logs, and core data/samples. The new data was used to refine reservoir and geologic characterization of these reservoirs. Further laboratory investigation also provided additional simulation input data in the form of PVT properties, relative permeabilities, capillary pressures, and water compatibility. Geologic investigations were also conducted to refine the models of mud-rich submarine fan architectures used by seismic analysts and reservoir engineers. These results were also used, in part, to assist in the recharacterization of these reservoirs.

  8. Integration of advanced geoscience and engineering techniques to quantify interwell heterogeneity in reservoir models. Final report, September 29, 1993--September 30, 1996

    SciTech Connect (OSTI)

    Weiss, W.W.; Buckley, J.S.; Ouenes, A.

    1997-05-01

    The goal of this three-year project was to provide a quantitative definition of reservoir heterogeneity. This objective was accomplished through the integration of geologic, geophysical, and engineering databases into a multi-disciplinary understanding of reservoir architecture and associated fluid-rock and fluid-fluid interactions. This interdisciplinary effort integrated geological and geophysical data with engineering and petrophysical results through reservoir simulation to quantify reservoir architecture and the dynamics of fluid-rock and fluid-fluid interactions. An improved reservoir description allows greater accuracy and confidence during simulation and modeling as steps toward gaining greater recovery efficiency from existing reservoirs. A field laboratory, the Sulimar Queen Unit, was available for the field research. Several members of the PRRC staff participated in the development of improved reservoir description by integration of the field and laboratory data as well as in the development of quantitative reservoir models to aid performance predictions. Subcontractors from Stanford University and the University of Texas at Austin (UT) collaborated in the research and participated in the design and interpretation of field tests. The three-year project was initiated in September 1993 and led to the development and application of various reservoir description methodologies. A new approach for visualizing production data graphically was developed and implemented on the Internet. Using production data and old gamma rays logs, a black oil reservoir model that honors both primary and secondary performance was developed. The old gamma ray logs were used after applying a resealing technique, which was crucial for the success of the project. In addition to the gamma ray logs, the development of the reservoir model benefitted from an inverse Drill Stem Test (DST) technique which provided initial estimates of the reservoir permeability at different wells.

  9. Opportunities for Biorenewables in Oil Refineries

    SciTech Connect (OSTI)

    Marker, T.L.

    2005-12-19

    Abstract: The purpose of this study was to evaluate the potential for using biorenewable feedstocks in oil refineries. Economic analyses were conducted, with support from process modeling and proof of principle experiments, to assess a variety of potential processes and configurations. The study considered two primary alternatives: the production of biodiesel and green diesel from vegetable oils and greases and opportunities for utilization of pyrolysis oil. The study identified a number of promising opportunities for biorenewables in existing or new refining operations.

  10. Predicting interwell heterogeneity in fluvial-deltaic reservoirs: Outcrop observations and applications of progressive facies variation through a depositional cycle

    SciTech Connect (OSTI)

    Knox, P.R.; Barton, M.D.

    1997-08-01

    Nearly 11 billion barrels of mobile oil remain in known domestic fluvial-deltaic reservoirs despite their mature status. A large percentage of this strategic resource is in danger of permanent loss through premature abandonment. Detailed reservoir characterization studies that integrate advanced technologies in geology, geophysics, and engineering are needed to identify remaining resources that can be targeted by near-term recovery methods, resulting in increased production and the postponement of abandonment. The first and most critical step of advanced characterization studies is the identification of reservoir architecture. However, existing subsurface information, primarily well logs, provides insufficient lateral resolution to identify low-permeability boundaries that exist between wells and compartmentalize the reservoir. Methods to predict lateral variability in fluvial-deltaic reservoirs have been developed on the basis of outcrop studies and incorporate identification of depositional setting and position within a depositional cycle. The position of a reservoir within the framework of a depositional cycle is critical. Outcrop studies of the Cretaceous Ferron Sandstone of Utah have demonstrated that the architecture and internal heterogeneity of sandstones deposited within a given depositional setting (for example, delta front) vary greatly depending upon whether they were deposited in the early, progradational part of a cycle or the late, retrogradational part of a cycle. The application of techniques similar to those used by this study in other fluvial-deltaic reservoirs will help to estimate the amount and style of remaining potential in mature reservoirs through a quicklook evaluation, allowing operators to focus characterization efforts on reservoirs that have the greatest potential to yield additional resources.

  11. Performance testing the Phase 2 HDR reservoir

    SciTech Connect (OSTI)

    Ponden, R.F.; Dreesen, D.S. ); Thomson, J.C. )

    1991-01-01

    The geothermal energy program at the Los Alamos National Laboratory is directed toward developing the Hot Dry Rock (HDR) technology as an alternate energy source. Positive results have been obtained in previous circulation tests of HDR reservoirs at the Laboratory's test site in Fenton Hill, New Mexico. There still remains however, the need to demonstrate that adequate geothermal energy can be extracted in an efficient manner to support commercial power production. This year, the Laboratory will begin a circulation test of its Phase 2, reservoir. The objectives of this test are to characterize steady-state power production and long-term reservoir performance. 6 refs., 2 figs., 3 tabs.

  12. DEVELOPMENT OF SHALLOW VISCOUS OIL RESERVES IN NORTH SLOPE

    SciTech Connect (OSTI)

    Kishore K. Mohanty

    2003-07-01

    North Slope of Alaska has huge oil deposits in heavy oil reservoirs such as Ugnu, West Sak and Shrader Bluff etc. The viscosity of the last two reservoir oils vary from {approx}30 cp to {approx}3000 cp and the amount in the range of 10-20 billion barrels. High oil viscosity and low formation strength impose problems to high recovery and well productivity. Water-alternate-gas injection processes can be effective for the lower viscosity end of these deposits in West Sak and Shrader Bluff. Several gas streams are available in the North Slope containing NGL and CO{sub 2} (a greenhouse gas). The goal of this research is to develop tools to find optimum solvent, injection schedule and well-architecture for a WAG process in North Slope shallow sand viscous oil reservoirs. In the last quarter, we have developed streamline generation and convection subroutines for miscible gas injection. The WAG injection algorithms are being developed. We formulated a four-phase relative permeability model based on two-phase relative permeabilities. The new relative permeability formulations are being incorporated into the simulator. Wettabilities and relative permeabilities are being measured. Plans for the next quarter includes modeling of WAG injection in streamline based simulation, relative permeability studies with cores, incorporation of complex well-architecture.

  13. SURFACTANT BASED ENHANCED OIL RECOVERY AND FOAM MOBILITY CONTROL

    SciTech Connect (OSTI)

    George J. Hirasaki; Clarence A. Miller; Gary A. Pope; Richard E. Jackson

    2004-07-01

    Surfactant flooding has the potential to significantly increase recovery over that of conventional waterflooding. The availability of a large number of surfactants makes it possible to conduct a systematic study of the relation between surfactant structure and its efficacy for oil recovery. Also, the addition of an alkali such as sodium carbonate makes possible in situ generation of surfactant and significant reduction of surfactant adsorption. In addition to reduction of interfacial tension to ultra-low values, surfactants and alkali can be designed to alter wettability to enhance oil recovery. An alkaline surfactant process is designed to enhance spontaneous imbibition in fractured, oil-wet, carbonate formations. It is able to recover oil from dolomite core samples from which there was no oil recovery when placed in formation brine. Mobility control is essential for surfactant EOR. Foam is evaluted to improve the sweep efficiency of surfactant injected into fractured reservoirs. UTCHEM is a reservoir simulator specially designed for surfactant EOR. A dual-porosity version is demonstrated as a potential scale-up tool for fractured reservoirs.

  14. STIMULI-RESPONSIVE POLYMERS WITH ENHANCED EFFICIENCY IN RESERVOIR RECOVERY PROCESSES

    SciTech Connect (OSTI)

    Charles McCormick; Roger Hester

    2004-09-30

    This sixth and final progress report for DOE Award Number DE-FC26-01BC15317 describes research during the period March 01, 2004 through August 31, 2004 performed at the University of Southern Mississippi on ''Stimuli Responsive Polymers with Enhanced Efficiency in Reservoir Recovery'' processes. Significantly, terpolymers that are responsive to changes in pH and ionic strength have been synthesized, characterized, and their solution properties have been extensively examined. Terpolymers composed of acrylamide, a carboxylated acrylamido monomer (AMBA), and a quaternary ammonium monomer (AMBATAC) with balanced compositions of the latter two, exhibit increases in aqueous solution viscosity as NaCl concentration is increased. This increase in polymer coil size can be expected upon injection of this type of polymer into oil reservoirs of moderate-to-high salinity, leading to better mobility control. The opposite effect (loss of viscosity) is observed for conventional polymer systems. Additionally polymer mobility characteristics have been conducted for a number of hydrophilic copolymers utilizing an extensional flow apparatus and size exclusion chromatography. This study reveled that oil recovery enhancement through use of polymers in a water flood is due to the polymer's resistance to deformation as it flows through the reservoir. Individual polymers when in aqueous solution form coils. The larger the polymer's coil size, the greater the polymer's resistance to extensional flow and the more effective the polymer is in enhancing oil recovery. Large coil sizes are obtained by increasing the polymer molecular weight and having macromolecular structures that favor greater swelling of the coil by the aqueous solvent conditions (temperature, pH and electrolyte concentration) existing in the reservoir.

  15. The Utilization of the Microflora Indigenous to and Present in Oil-Bearing Formations to Selectively Plug the More Porous Zones Thereby Increasing Oil Recovery During Waterflooding

    SciTech Connect (OSTI)

    Brown, Lewis R.; Byrnes, Martin J.; Stephens, James O.; Vadie, Alex A.

    1999-07-01

    This project was designed to demonstrate that a microbially enhanced oil recovery process (MEOR), developed in part under DOE Contract No. DE-AC22-90BC14665, will increase oil recovery from fluvial dominated deltaic oil reservoirs. The process involves stimulating the in-situ indigenous microbial population in the reservoir to grow in the more permeable zones, thus diverting flow to other areas of the reservoir, thereby increasing the effectiveness of the waterflood. This five and a half year project is divided into three phases, Phase I, Planning and Analysis (9 months), Phase II, Implementation (45 months), and Phase III, Technology Transfer (12 months). Phase I was completed and reported in the first annual report. This fifth annual report covers the completion of Phase II and the first six months of Phase III.

  16. Marginal Expense Oil Well Wireless Surveillance (MEOWWS)

    SciTech Connect (OSTI)

    Nelson, Donald G.

    2002-03-11

    The objective of this study was to identify and field test a new, low cost, wireless oil well surveillance system. A variety of suppliers and technologies were considered. One supplier and system was chosen that was low cost, new to the oil field, and successfully field tested.

  17. Major Oil Plays in Utah and Vicinity

    SciTech Connect (OSTI)

    Thomas C. Chidsey; Craig D. Morgan; Kevin McClure; Douglas A. Sprinkel; Roger L. Bon; Hellmut H. Doelling

    2003-12-31

    Utah oil fields have produced over 1.2 billion barrels (191 million m{sup 3}). However, the 13.7 million barrels (2.2 million m{sup 3}) of production in 2002 was the lowest level in over 40 years and continued the steady decline that began in the mid-1980s. The Utah Geological Survey believes this trend can be reversed by providing play portfolios for the major oil-producing provinces (Paradox Basin, Uinta Basin, and thrust belt) in Utah and adjacent areas in Colorado and Wyoming. Oil plays are geographic areas with petroleum potential caused by favorable combinations of source rock, migration paths, reservoir rock characteristics, and other factors. The play portfolios will include: descriptions and maps of the major oil plays by reservoir; production and reservoir data; case-study field evaluations; locations of major oil pipelines; identification and discussion of land-use constraints; descriptions of reservoir outcrop analogs; and summaries of the state-of-the-art drilling, completion, and secondary/tertiary techniques for each play. This report covers research activities for the sixth quarter of the project (October 1 through December 31, 2003). This work included describing outcrop analogs for the Jurassic Twin Creek Limestone and Mississippian Leadville Limestone, major oil producers in the thrust belt and Paradox Basin, respectively, and analyzing best practices used in the southern Green River Formation play of the Uinta Basin. Production-scale outcrop analogs provide an excellent view of reservoir petrophysics, facies characteristics, and boundaries contributing to the overall heterogeneity of reservoir rocks. They can be used as a ''template'' for evaluation of data from conventional core, geophysical and petrophysical logs, and seismic surveys. In the Utah/Wyoming thrust belt province, the Jurassic Twin Creek Limestone produces from subsidiary closures along major ramp anticlines where the low-porosity limestone beds are extensively fractured and sealed by overlying argillaceous and non-fractured units. The best outcrop analogs for Twin Creek reservoirs are found at Devils Slide and near the town of Peoa, Utah, where fractures in dense, homogeneous non-porous limestone beds are in contact with the basal siltstone units (containing sealed fractures) of the overlying units. The shallow marine, Mississippian Leadville Limestone is a major oil and gas reservoir in the Paradox Basin of Utah and Colorado. Hydrocarbons are produced from basement-involved, northwest-trending structural traps with closure on both anticlines and faults. Excellent outcrops of Leadville-equivalent rocks are found along the south flank of the Uinta Mountains, Utah. For example, like the Leadville, the Mississippian Madison Limestone contains zones of solution breccia, fractures, and facies variations. When combined with subsurface geological and production data, these outcrop analogs can improve (1) development drilling and production strategies such as horizontal drilling, (2) reservoir-simulation models, (3) reserve calculations, and (4) design and implementation of secondary/tertiary oil recovery programs and other best practices used in the oil fields of Utah and vicinity. In the southern Green River Formation play of the Uinta Basin, optimal drilling, development, and production practices consist of: (1) owning drilling rigs and frac holding tanks; (2) perforating sandstone beds with more than 8 percent neutron porosity and stimulate with separate fracture treatments; (3) placing completed wells on primary production using artificial lift; (4) converting wells relatively soon to secondary waterflooding maintaining reservoir pressure above the bubble point to maximize oil recovery; (5) developing waterflood units using an alternating injector--producer pattern on 40-acre (16-ha) spacing; and (6) recompleting producing wells by perforating all beds that are productive in the waterflood unit. As part of technology transfer activities during this quarter, an abstract describing outcrop reservoir analogs was accepted by the American Association of Petroleum Geologists, for presentation at the 2004 annual meeting in Dallas, Texas. Another abstract was submitted for consideration on basin-wide correlation of Green River Formation plays and subplays in the Uinta Basin in Utah. The project home page was updated on the Utah Geological Survey Internet web site.

  18. Parallel, Multigrid Finite Element Simulator for Fractured/Faulted and Other Complex Reservoirs based on Common Component Architecture (CCA)

    SciTech Connect (OSTI)

    Milind Deo; Chung-Kan Huang; Huabing Wang

    2008-08-31

    Black-oil, compositional and thermal simulators have been developed to address different physical processes in reservoir simulation. A number of different types of discretization methods have also been proposed to address issues related to representing the complex reservoir geometry. These methods are more significant for fractured reservoirs where the geometry can be particularly challenging. In this project, a general modular framework for reservoir simulation was developed, wherein the physical models were efficiently decoupled from the discretization methods. This made it possible to couple any discretization method with different physical models. Oil characterization methods are becoming increasingly sophisticated, and it is possible to construct geologically constrained models of faulted/fractured reservoirs. Discrete Fracture Network (DFN) simulation provides the option of performing multiphase calculations on spatially explicit, geologically feasible fracture sets. Multiphase DFN simulations of and sensitivity studies on a wide variety of fracture networks created using fracture creation/simulation programs was undertaken in the first part of this project. This involved creating interfaces to seamlessly convert the fracture characterization information into simulator input, grid the complex geometry, perform the simulations, and analyze and visualize results. Benchmarking and comparison with conventional simulators was also a component of this work. After demonstration of the fact that multiphase simulations can be carried out on complex fracture networks, quantitative effects of the heterogeneity of fracture properties were evaluated. Reservoirs are populated with fractures of several different scales and properties. A multiscale fracture modeling study was undertaken and the effects of heterogeneity and storage on water displacement dynamics in fractured basements were investigated. In gravity-dominated systems, more oil could be recovered at a given pore volume of injection at lower rates. However, if oil production can be continued at high water cuts, the discounted cumulative production usually favors higher production rates. The workflow developed during the project was also used to perform multiphase simulations in heterogeneous, fracture-matrix systems. Compositional and thermal-compositional simulators were developed for fractured reservoirs using the generalized framework. The thermal-compositional simulator was based on a novel 'equation-alignment' approach that helped choose the correct variables to solve depending on the number of phases present and the prescribed component partitioning. The simulators were used in steamflooding and in insitu combustion applications. The framework was constructed to be inherently parallel. The partitioning routines employed in the framework allowed generalized partitioning on highly complex fractured reservoirs and in instances when wells (incorporated in these models as line sources) were divided between two or more processors.

  19. Simulation and resistivity modeling of a geothermal reservoir with waters of different salinity

    SciTech Connect (OSTI)

    Pruess, K.; Wilt, M.; Bodvarsson, G.S.; Goldstein, N.E.

    1982-10-01

    Apparent resistivities measured by means of repetitive dipole-dipole surveys show significant changes within the Cerro Prieto reservoir. The changes are attributed to production and natural recharge. To better understand the observed geophysical phenomena a simple reservoir simulation study combined with the appropriate DC resistivity calculations to determine the expected magnitude of apparent resistivity change. We consider production from a liquid-dominated reservoir with dimensions and parameters of the Cerro Prieto A reservoir and assume lateral and vertical recharge of colder and less saline waters. Based on rather schematic one- and two-dimensional reservoir simulations, we calculate changes in formation resistivity which we then transform into changes in apparent resistivity that would be observed at the surface. Simulated changes in apparent resistivities over the production zone show increases of 10 to 20% over a 3 year period at the current rate of fluid extraction. Changes of this magnitude are not only within our ability to discern using proper field techniques, but are consistent in magnitude with some of the observed effects. However, the patterns of apparent resistivity changes in the simulated dipole-dipole pseudosection only partially resemble the observed field data. This is explained by the fact that the actual fluid recharge into the A reservoir is more complicated than assumed in our simple, schematic recharge models.

  20. HETEROGENEOUS SHALLOW-SHELF CARBONATE BUILDUPS IN THE PARADOX BASIN, UTAH AND COLORADO: TARGETS FOR INCREASED OIL PRODUCTION AND RESERVES USING HORIZONTAL DRILLING TECHNIQUES

    SciTech Connect (OSTI)

    David E. Eby; Thomas C. Chidsey, Jr.; Kevin McClure; Craig D. Morgan

    2003-07-01

    The Paradox Basin of Utah, Colorado, Arizona, and New Mexico contains nearly 100 small oil fields producing from carbonate buildups within the Pennsylvanian (Desmoinesian) Paradox Formation. These fields typically have one to 10 wells with primary production ranging from 700,000 to 2,000,000 barrels (111,300-318,000 m{sup 3}) of oil per field and a 15 to 20 percent recovery rate. At least 200 million barrels (31.8 million m{sup 3}) of oil will not be recovered from these small fields because of inefficient recovery practices and undrained heterogeneous reservoirs. Several fields in southeastern Utah and southwestern Colorado are being evaluated as candidates for horizontal drilling and enhanced oil recovery from existing vertical wells based upon geological characterization and reservoir modeling case studies. Geological characterization on a local scale is focused on reservoir heterogeneity, quality, and lateral continuity, as well as possible reservoir compartmentalization, within these fields. This study utilizes representative cores, geophysical logs, and thin sections to characterize and grade each field's potential for drilling horizontal laterals from existing development wells. The results of these studies can be applied to similar fields elsewhere in the Paradox Basin and the Rocky Mountain region, the Michigan and Illinois Basins, and the Midcontinent region. This report covers research activities for the second half of the third project year (October 6, 2002, through April 5, 2003). The primary work included describing and mapping regional facies of the upper Ismay and lower Desert Creek zones of the Paradox Formation in the Blanding sub-basin, Utah. Regional cross sections show the development of ''clean carbonate'' packages that contain all of the productive reservoir facies. These clean carbonates abruptly change laterally into thick anhydrite packages that filled several small intra-shelf basins in the upper Ismay zone. Examination of upper Ismay cores identified seven depositional facies: open marine, middle shelf, inner shelf/tidal flat, bryozoan mounds, phylloid-algal mounds, quartz sand dunes, and anhydritic salinas. Lower Desert Creek facies include open marine, middle shelf, protomounds/collapse breccia, and phylloid-algal mounds. Mapping the upper Ismay zone facies delineates very prospective reservoir trends that contain porous, productive buildups around the anhydrite-filled intra-shelf basins. Facies and reservoir controls imposed by the anhydritic intra-shelf basins should be considered when selecting the optimal location and orientation of any horizontal drilling from known phylloidalgal reservoirs to undrained reserves, as well as identifying new exploration trends. Although intra-shelf basins are not present in the lower Desert Creek zone of the Blanding sub-basin, drilling horizontally along linear shoreline trends could also encounter previously undrilled, porous intervals and buildups. Technology transfer activities consisted of a technical presentation at a Class II Review conference sponsored by the National Energy Technology Laboratory at the Center for Energy and Economic Diversification in Odessa, Texas. The project home page was updated on the Utah Geological Survey Internet web site.