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Note: This page contains sample records for the topic "natural geological reservoir" from the National Library of EnergyBeta (NLEBeta).
While these samples are representative of the content of NLEBeta,
they are not comprehensive nor are they the most current set.
We encourage you to perform a real-time search of NLEBeta
to obtain the most current and comprehensive results.


1

Geology and Reservoir Simulation  

NLE Websites -- All DOE Office Websites (Extended Search)

Service: 1-800-553-7681 Geology and Reservoir Simulation Background Natural gas from shale is becoming ever more recognized as an abundant and economically viable fuel in the...

2

ADVANCED TECHNOLOGY FOR PREDICTING THE FLUID FLOW ATTRIBUTES OF NATURALLY FRACTURED RESERVOIRS FROM QUANTITATIVE GEOLOGIC DATA AND MODELING  

Science Conference Proceedings (OSTI)

This report summarizes the work carried out during the period of September 29, 2000 to January 15, 2004 under DOE Research Contract No. DE-FC26-00BC15308. High temperatures and reactive fluids in sedimentary basins dictate that interplay and feedback between mechanical and geochemical processes significantly influence evolving rock and fracture properties. Not only does diagenetic mineralization fill in once open fractures either partially or completely, it modifies the rock mechanics properties that can control the mechanical aperture of natural fractures. In this study, we have evolved an integrated methodology of fractured reservoir characterization and we have demonstrated how it can be incorporated into fluid flow simulation. The research encompassed a wide range of work from geological characterization methods to rock mechanics analysis to reservoir simulation. With regard to the characterization of mineral infilling of natural fractures, the strong interplay between diagenetic and mechanical processes is documented and shown to be of vital importance to the behavior of many types of fractured reservoirs. Although most recent literature emphasizes Earth stress orientation, cementation in fractures is likely a critically important control on porosity, fluid flow attributes, and even sensitivity to effective stress changes. The diagenetic processes of dissolution and partial cementation are key controls on the creation and distribution of open natural fractures within hydrocarbon reservoirs. The continuity of fracture-porosity is fundamental to how fractures conduct fluids. In this study, we have made a number of important discoveries regarding fundamental properties of fractures, in particular related to the prevalence of kinematically significant structures (crack-seal texture) within otherwise porous, opening-mode fractures, and the presence of an aperture size threshold below which fractures are completely filled and above which porosity is preserved. These observations can be linked to models of quartz cementation. Significant progress has been made as well in theoretical fracture mechanics and geomechanical modeling, allowing prediction of spatial distributions of fractures that mimic patterns observed in nature. Geomechanical modeling shows the spatial arrangement of opening mode fractures (joints and veins) is controlled by the subcritical fracture index of the material. In particular, we have been able to identify mechanisms that control the clustering of fractures in slightly deformed rocks. Fracture mechanics testing of a wide range of clastic rocks shows that the subcritical index is sensitive to diagenetic factors. We show geomechanical simulations of fracture aperture development can be linked to diagenetic models, modifying fracture porosity as fractures grow, and affect the dynamics of fracture propagation. Fluid flow simulation of representative fracture pattern realizations shows how integrated modeling can give new insight into permeability assessment in the subsurface. Using realistic, geomechanically generated fracture patterns, we propose a methodology for permeability estimation in nonpercolating networks.

Jon E. Olson; Larry W. Lake; Steve E. Laubach

2004-11-01T23:59:59.000Z

3

ADVANCED TECHNOLOGY FOR PREDICTING THE FLUID FLOW ATTRIBUTES OF NATURALLY FRACTURED RESERVOIRS FROM QUANTITATIVE GEOLOGIC DATA AND MODELING  

Science Conference Proceedings (OSTI)

This report summarizes the work carried out during the period of September 29, 2000 to September 28, 2001 under DOE Research Contract No. DE-FC26-00BC15308. Our goal is to establish an integrated methodology of fractured reservoir characterization and show how that can be incorporated into fluid flow simulation. We have made progress in the characterization of mineral infilling of natural fractures. The main advancement in this regard was to recognize the strong interplay between diagenetic and mechanical processes. We accomplished several firsts in documenting and quantifying these processes, including documenting the range of emergent threshold in several formations and quantifying the internal structures of crack-seal bridges in fractures. These results will be the basis for an appreciation of fracture opening and filling rates that go well beyond our original goals. Looking at geochemical modeling of fracture infilling, our theoretical analysis addressed the problem of calcite precipitation in a fracture. We have built a model for the deposition of calcite within a fracture. The diagenetic processes of dissolution and partial cementation are key controls on the creation and distribution of natural fractures within hydrocarbon reservoirs. Even with extensive data collection, fracture permeability still creates uncertainty in reservoir description and the prediction of well performance. Data on the timing and stages of diagenetic events can provide explanation as to why, when and where natural fractures will be open and permeable. We have been pursuing the fracture mechanics testing of a wide range of rocks, particularly sandstone using a key rock property test that has hitherto not been widely applied to sedimentary rocks. A major accomplishment in this first year has been to identify sample suites available in the core repository at the University of Texas that represent a wide range of diagenetic alteration and to begin to test these samples. The basis for the fluid flow simulations to be carried out in this part of the project is the adequate spatial characterization of fracture networks. Our initial focus has been on the tendency of fracture sets to cluster into highly fracture zones that are often widely separated. Our preliminary modeling work shows the extent of this clustering to be controlled by the subcritical fracture index of the material. With continued progress, we move toward an integrated fracture characterization methodology that will ultimately be applied through detailed reservoir simulation.

Jon E. Olson; Larry W. Lake; Steve E. Laubach

2003-04-01T23:59:59.000Z

4

Underground natural gas storage reservoir management  

SciTech Connect

The objective of this study is to research technologies and methodologies that will reduce the costs associated with the operation and maintenance of underground natural gas storage. This effort will include a survey of public information to determine the amount of natural gas lost from underground storage fields, determine the causes of this lost gas, and develop strategies and remedial designs to reduce or stop the gas loss from selected fields. Phase I includes a detailed survey of US natural gas storage reservoirs to determine the actual amount of natural gas annually lost from underground storage fields. These reservoirs will be ranked, the resultant will include the amount of gas and revenue annually lost. The results will be analyzed in conjunction with the type (geologic) of storage reservoirs to determine the significance and impact of the gas loss. A report of the work accomplished will be prepared. The report will include: (1) a summary list by geologic type of US gas storage reservoirs and their annual underground gas storage losses in ft{sup 3}; (2) a rank by geologic classifications as to the amount of gas lost and the resultant lost revenue; and (3) show the level of significance and impact of the losses by geologic type. Concurrently, the amount of storage activity has increased in conjunction with the net increase of natural gas imports as shown on Figure No. 3. Storage is playing an ever increasing importance in supplying the domestic energy requirements.

Ortiz, I.; Anthony, R.

1995-06-01T23:59:59.000Z

5

Real natural gas reservoir data Vs. natural gas reservoir models  

Science Conference Proceedings (OSTI)

The gas reservoir per se model is an exceedingly simple model of a natural gas reservoir designed to develop the physical relationship between ultimate recovery and rate(s) of withdrawal for production regulation policy assessment. To be responsive, ...

Ellis A. Monash; John Lohrenz

1979-03-01T23:59:59.000Z

6

FMI Borehole Geology, Geomechanics and 3D Reservoir Modeling...  

Open Energy Info (EERE)

NA, 2002 DOI Not Provided Check for DOI availability: http:crossref.org Online Internet link for FMI Borehole Geology, Geomechanics and 3D Reservoir Modeling Citation...

7

Scales of geologic reservoir description for engineering applications  

SciTech Connect

A consequence of the increased interaction between geologists and engineers in resolving reservoir problems has been an awareness on the part of geologists of the need to vary the scale of their geologic description according to particular engineering applications. Conventional geological descriptions are normally too detailed for reservoir engineering simulations and often are not in an appropriate form for relating to reservoir performance. An example is presented of two scales of description of a North Sea oil field for two different applications. The field is a Tertiary submarine slope-fan deposit consisting of thick unconsolidated channel sand facies, a lobe sand facies, and a slope claystone facies, all arranged into 12 stratigraphic units and several subunits. Permeability of the channel sands is about twice that of lobe sands, demonstrating a facies control on reservoir quality. For the purpose of calculating reservoir volumetrics, it was possible to scale up the stratigraphy, by combining similar stratigraphic units, into a simple four-layer reservoir model. Average porosity and permeability vary among the layers in this geologically based model. For the purpose of improving understanding of the reservoir, a more complex flow unit model was developed according to geological and petrophysical properties that would influence the flow of fluids in the reservoir. This model is partly based upon sedimentary facies distribution, but differs from a geologic facies model and is in a more suitable form for relating to reservoir performance.

Slatt, R.M.; Hopkins, G.L.

1988-01-01T23:59:59.000Z

8

Horizontal drilling in shallow, geologically complex reservoirs  

Science Conference Proceedings (OSTI)

The objective of this project is to test the concept that multiple hydraulic fracturing from a directionally-drilled horizontal well, using the medium radius build rate method, can increase gas production sufficiently to justify economic viability over conventional stimulated vertical wells. The test well is located in Yuma County, Colorado, in a favorable area of established production to avoid exploration risks. This report presents: background information; project description which covers location selection/geologic considerations; and preliminary work plan. (AT)

Venable, S.D.

1992-01-01T23:59:59.000Z

9

Horizontal drilling in shallow, geologically complex reservoirs  

Science Conference Proceedings (OSTI)

The objective of this project is to test the concept that multiple hydraulic fracturing from a directionally-drilled horizontal well, using the medium radius build rate method, can increase gas production sufficiently to justify economic viability over conventional stimulated vertical wells. The test well is located in Yuma County, Colorado, in a favorable area of established production to avoid exploration risks. This report presents: background information; project description which covers location selection/geologic considerations; and preliminary work plan. (AT)

Venable, S.D.

1992-10-01T23:59:59.000Z

10

Naturally fractured tight gas reservoir detection optimization  

SciTech Connect

Research continued on methods to detect naturally fractured tight gas reservoirs. This report discusses 3D-3C seismic acquisition and 3D P-wave alternate processing.

NONE

1995-12-31T23:59:59.000Z

11

US production of natural gas from tight reservoirs  

Science Conference Proceedings (OSTI)

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.

Not Available

1993-10-18T23:59:59.000Z

12

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....

13

New Mexico - East Dry Natural Gas New Reservoir Discoveries in...  

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

Dry Natural Gas New Reservoir Discoveries in Old Fields (Billion Cubic Feet) New Mexico - East Dry Natural Gas New Reservoir Discoveries in Old Fields (Billion Cubic Feet) Decade...

14

New Mexico - West Dry Natural Gas New Reservoir Discoveries in...  

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

Dry Natural Gas New Reservoir Discoveries in Old Fields (Billion Cubic Feet) New Mexico - West Dry Natural Gas New Reservoir Discoveries in Old Fields (Billion Cubic Feet) Decade...

15

A STUDY ON GEOTHERMAL RESERVOIR ENGlNEERING APPROACH COMBINED WITH GEOLOGICAL INFORMATIONS  

SciTech Connect

This paper presents the combined approaches of reservoir geology and engineering to a geothermal field where geological characteristics are highly complex and heterogeneous.Especially,the concrete approaches are discussed for the case of geothermal reservoir performance studies with a developed numerical model, by showing example cases accompanied with reinjection of produced disposal hot water into underground in an object geothermal reservoir. This combined approach will be a great help in solving complicated problems encountered during the development of a geothermal field.

Hirakawa, S.; Yamaguchi, S.; Yoshinobu, F.

1985-01-22T23:59:59.000Z

16

Utah Natural Gas, Wet After Lease Separation New Reservoir Discoveries...  

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

New Reservoir Discoveries in Old Fields (Billion Cubic Feet) Utah Natural Gas, Wet After Lease Separation New Reservoir Discoveries in Old Fields (Billion Cubic Feet) Decade Year-0...

17

Utah Nonassociated Natural Gas, Reserves in Nonproducing Reservoirs...  

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

Reserves in Nonproducing Reservoirs, Wet (Billion Cubic Feet) Utah Nonassociated Natural Gas, Reserves in Nonproducing Reservoirs, Wet (Billion Cubic Feet) Decade Year-0 Year-1...

18

California Federal Offshore Dry Natural Gas New Reservoir Discoveries...  

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

New Reservoir Discoveries in Old Fields (Billion Cubic Feet) California Federal Offshore Dry Natural Gas New Reservoir Discoveries in Old Fields (Billion Cubic Feet) Decade Year-0...

19

Optimal Reservoir Management and Well Placement Under Geologic Uncertainty  

E-Print Network (OSTI)

Reservoir management, sometimes referred to as asset management in the context of petroleum reservoirs, has become recognized as an important facet of petroleum reservoir development and production operations. In the first stage of planning field development, the simulation model is calibrated to dynamic data (history matching). One of the aims of the research is to extend the streamline based generalized travel time inversion method for full field models with multimillion cells through the use of grid coarsening. This makes the streamline based inversion suitable for high resolution simulation models with decades long production history and numerous wells by significantly reducing the computational effort. In addition, a novel workflow is proposed to integrate well bottom-hole pressure data during model calibration and the approach is illustrated via application to the CO2 sequestration. In the second stage, field development strategies are optimized. The strategies are primarily focused on rate optimization followed by infill well drilling. A method is proposed to modify the streamline-based rate optimization approach which previously focused on maximizing sweep efficiency by equalizing arrival time of the waterfront to producers, to account for accelerated production for improving the net present value (NPV). Optimum compromise between maximizing sweep efficiency and maximizing NPV can be selected based on a 'trade-off curve.' The proposed method is demonstrated on field scale application considering geological uncertainty. Finally, a novel method for well placement optimization is proposed that relies on streamlines and time of flight to first locate the potential regions of poorly swept and drained oil. Specifically, the proposed approach utilizes a dynamic measure based on the total streamline time of flight combined with static and dynamic parameters to identify "Sweet-Spots" for infill drilling. The "Sweet-Spots" can be either used directly as potential well-placement locations or as starting points during application of a formal optimization technique. The main advantage of the proposed method is its computational efficiency in calculating dynamic measure map. The complete workflow was also demonstrated on a multimillion cell reservoir model of a mature carbonate field with notable success. The infill locations based on dynamic measure map have been verified by subsequent drilling.

Taware, Satyajit Vijay

2012-08-01T23:59:59.000Z

20

Scales of geologic reservoir description for engineering applications: North Sea oil field example  

SciTech Connect

A consequence of the increased interaction between geologists and engineers in resolving reservoir problems has been an awareness on the part of geologists of the need to vary the scale of their geologic description according to particular engineering applications. Conventional geological descriptions are normally too detailed for reservoir engineering simulations and often are not in an appropriate form for relating to reservoir performance. An example is presented of two scales of description of a North Sea oil field for two different applications. The field is a Tertiary submarine slope-fan deposit consisting of thick unconsolidated channel sand facies, a lobe sand facies, and a slope claystone facies, all arranged into 12 stratigraphic units and several subunits. Permeability of the channel sands is about twice that of lobe sands, demonstrating a facies control on reservoir quality. For the purpose of calculating reservoir volumetrics, it was possible to scale up the stratigraphy, by combining similar stratigraphic units, into a simple four-layer reservoir model. Average porosity and permeability vary among the layers in this geologically based model. For the purpose of improving understanding of the reservoir, a more complex flow unit model was developed according to geological and petrophysical properties that would influence the flow of fluids in the reservoir. This model is partly based upon sedimentary facies distribution, but differs from a geologic facies model and is in a more suitable form for relating to reservoir performance.

Slatt, R.M.; Hopkins, G.L.

1988-02-01T23:59:59.000Z

Note: This page contains sample records for the topic "natural geological reservoir" from the National Library of EnergyBeta (NLEBeta).
While these samples are representative of the content of NLEBeta,
they are not comprehensive nor are they the most current set.
We encourage you to perform a real-time search of NLEBeta
to obtain the most current and comprehensive results.


21

Pressure transient analysis for naturally fractured reservoirs  

Science Conference Proceedings (OSTI)

New ideas are presented for the interpretation of pressure transient tests for wells in naturally fractured reservoirs. This work is based on the transient matrix flow model formulated by de Swaan. The differences between this model and the Warren and Root model occur during the transition flow period. It is demonstrated that the behavior of a naturally fractured reservoir can be correlated by using three dimensionless parameters. It is established that regardless of matrix geometry the transition period might exhibit a straight line whose slope is equal to half the slope of the classical parallel semilog straight lines, provided the transient matrix linear flow is present. In addition, information is provided on the estimation of fracture area per unit matrix volume or matrix parameters from the transition period semilog straight line. It is shown that matrix geometry might be identified when pressure data are smooth. Field examples are included to illustrate the application and the validity of the theoretical results of this study.

Cinco-ley, H.; Samaniego, F.V.

1982-09-01T23:59:59.000Z

22

EIA - Natural Gas Pipeline Network - Aquifer Storage Reservoir...  

Annual Energy Outlook 2012 (EIA)

Aquifer Storage Reservoir Configuration About U.S. Natural Gas Pipelines - Transporting Natural Gas based on data through 20072008 with selected updates Aquifer Underground...

23

EIA - Natural Gas Pipeline Network - Depleted Reservoir Storage...  

Annual Energy Outlook 2012 (EIA)

Depleted Reservoir Storage Configuration About U.S. Natural Gas Pipelines - Transporting Natural Gas based on data through 20072008 with selected updates Depleted Production...

24

Predicting the occurrence of open natural fractures in shale reservoirs  

SciTech Connect

Prolific oil and gas production has been established from naturally fractured shale reservoirs. For example, in the last few years over 4 Tcf of gas reserves have been established within the self-sourcing Antrim Shale of the Michigan Basin. Historically, locating subsurface fracture systems essential for commercial production has proven elusive and costly. An integrated exploration approach utilizing available geologic, geophysical, and remote sensing data has successfully located naturally fractured zones within the Antrim Shale. It is believed that fracturing of the Antrim shale was a result of basement involved tectonic processes. Characteristic integrated stacked signatures of known fracture systems within the Antrim were built using gravity and magnetic data, structure maps, fracture identification logs, and Landsat imagery. Wireline fracture logs pinpointed the locations and geometries of subsurface fracture systems. Landsat imagery was interpreted to reveal surficial manifestations of subsurface structures.

Decker, A.D.; Klawitter, A.L. (Advanced Resources International, Denver, CO (United States))

1996-01-01T23:59:59.000Z

25

Utah Dry Natural Gas New Reservoir Discoveries in Old Fields...  

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

New Reservoir Discoveries in Old Fields (Billion Cubic Feet) Utah Dry Natural Gas New Reservoir Discoveries in Old Fields (Billion Cubic Feet) Decade Year-0 Year-1 Year-2 Year-3...

26

California Dry Natural Gas New Reservoir Discoveries in Old Fields...  

Annual Energy Outlook 2012 (EIA)

New Reservoir Discoveries in Old Fields (Billion Cubic Feet) California Dry Natural Gas New Reservoir Discoveries in Old Fields (Billion Cubic Feet) Decade Year-0 Year-1 Year-2...

27

Ohio Dry Natural Gas New Reservoir Discoveries in Old Fields...  

Annual Energy Outlook 2012 (EIA)

New Reservoir Discoveries in Old Fields (Billion Cubic Feet) Ohio Dry Natural Gas New Reservoir Discoveries in Old Fields (Billion Cubic Feet) Decade Year-0 Year-1 Year-2 Year-3...

28

Michigan Dry Natural Gas New Reservoir Discoveries in Old Fields...  

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

New Reservoir Discoveries in Old Fields (Billion Cubic Feet) Michigan Dry Natural Gas New Reservoir Discoveries in Old Fields (Billion Cubic Feet) Decade Year-0 Year-1 Year-2...

29

Colorado Dry Natural Gas New Reservoir Discoveries in Old Fields...  

Gasoline and Diesel Fuel Update (EIA)

New Reservoir Discoveries in Old Fields (Billion Cubic Feet) Colorado Dry Natural Gas New Reservoir Discoveries in Old Fields (Billion Cubic Feet) Decade Year-0 Year-1 Year-2...

30

Texas Dry Natural Gas New Reservoir Discoveries in Old Fields...  

Gasoline and Diesel Fuel Update (EIA)

New Reservoir Discoveries in Old Fields (Billion Cubic Feet) Texas Dry Natural Gas New Reservoir Discoveries in Old Fields (Billion Cubic Feet) Decade Year-0 Year-1 Year-2 Year-3...

31

The Tiwi geothermal reservoir: Geology, geochemistry, and response to production  

Science Conference Proceedings (OSTI)

The Tiwi geothermal field is located on the Bicol Peninsula of Southern Luzon in the Philippines. The field is associated with the extinct Quaternary stratovolcano Mt. Malinao, one of a chain of volcanos formed as a result of crustal subduction along the Philippine Trench to the east. The geothermal reservoir is contained within a sequence of interlayered andesite flows and pyroclastic deposits that unconformably overlie a basement complex of marine sediments, metamorphic, and intrusive rocks. In its initial state, the Tiwi reservoir was an overpressured liquid-filled system containing near-neutral sodium chloride water at temperatures exceeding 260{degree}C. The reservoir is partially sealed at its top and sides by hydrothermal argillic alteration products and calcite deposition. Isolated portions of the reservoir contain a corrosive acid chloride-sulfate water associated with a distinctive advanced argillic mineral assemblage. Withdrawal of fluid for electricity generation has caused widespread boiling in the reservoir and the formation of steam zones. The resultant solids deposition in wellbores and near-wellbore formation has been mitigated by a combination of mechanical and chemical well stimulation. Mass withdrawal from the reservoir has also caused invasion of cold groundwater into the reservoir through former fluid outflow channels. During 1983-1987, several wells were flooded with cold water and ceased flowing. In response, PGI moved development drilling west to largely unaffected areas and undertook recompletion and stimulation programs. These programs effectively halted the decline in generation by 1988.

Hoagland, J.R.; Bodell, J.M. (Unocal Geothermal Div., Santa Rosa, CA (USA))

1990-06-01T23:59:59.000Z

32

Naturally fractured tight gas reservoir detection optimization  

SciTech Connect

Building upon the partitioning of the Greater Green River Basin (GGRB) that was conducted last quarter, the goal of the work this quarter has been to conclude evaluation of the Stratos well and the prototypical Green River Deep partition, and perform the fill resource evaluation of the Upper Cretaceous tight gas play, with the goal of defining target areas of enhanced natural fracturing. The work plan for the quarter of November 1-December 31, 1998 comprised four tasks: (1) Evaluation of the Green River Deep partition and the Stratos well and examination of potential opportunity for expanding the use of E and P technology to low permeability, naturally fractured gas reservoirs, (2) Gas field studies, and (3) Resource analysis of the balance of the partitions.

NONE

1999-06-01T23:59:59.000Z

33

,"Shale Natural Gas New Reservoir Discoveries in Old Fields ...  

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

,"Worksheet Name","Description"," Of Series","Frequency","Latest Data for" ,"Data 1","Shale Natural Gas New Reservoir Discoveries in Old Fields ",36,"Annual",2011,"6302009"...

34

,"California Dry Natural Gas New Reservoir Discoveries in Old...  

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

Name","Description"," Of Series","Frequency","Latest Data for" ,"Data 1","California Dry Natural Gas New Reservoir Discoveries in Old Fields (Billion Cubic...

35

,"Texas Dry Natural Gas New Reservoir Discoveries in Old Fields...  

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

,"Worksheet Name","Description"," Of Series","Frequency","Latest Data for" ,"Data 1","Texas Dry Natural Gas New Reservoir Discoveries in Old Fields (Billion Cubic...

36

,"New Mexico Dry Natural Gas New Reservoir Discoveries in Old...  

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

Name","Description"," Of Series","Frequency","Latest Data for" ,"Data 1","New Mexico Dry Natural Gas New Reservoir Discoveries in Old Fields (Billion Cubic...

37

Naturally fractured tight gas reservoir detection optimization  

SciTech Connect

The goal of the work this quarter has been to partition and high-grade the Greater Green River basin for exploration efforts in the Upper Cretaceous tight gas play and to initiate resource assessment of the basin. The work plan for the quarter of July 1-September 30, 1998 comprised three tasks: (1) Refining the exploration process for deep, naturally fractured gas reservoirs; (2) Partitioning of the basin based on structure and areas of overpressure; (3) Examination of the Kinney and Canyon Creek fields with respect to the Cretaceous tight gas play and initiation of the resource assessment of the Vermilion sub-basin partition (which contains these two fields); and (4) Initiation analysis of the Deep Green River Partition with respect to the Stratos well and assessment of the resource in the partition.

NONE

1998-11-30T23:59:59.000Z

38

Studies of injection into naturally fractured reservoirs  

DOE Green Energy (OSTI)

A semi-analytical model for studies of cold water injection into naturally fractured reservoirs has been developed. The model can be used to design the flow rates and location of injection wells in such systems. The results obtained using the model show that initially the cold water will move very rapidly through the fracture system away from the well. Later on, conductive heat transfer from the rock matrix blocks will retard the advancement of the cold water front, and eventually uniform energy sweep conditions will prevail. Where uniform energy sweep conditions are reached the cold waer movement away from the injection well will be identical to that in a porous medium; consequently maximum energy recovery from the rock matrix will be attained. The time of uniform energy sweep and the radial distance from the injection well where it occurs are greatly dependent upon the fracture spacing, but independent of the fracture aperture.

Boedvarsson, G.S.; Lai, C.H.

1982-10-01T23:59:59.000Z

39

Potential hazards of compressed air energy storage in depleted natural gas reservoirs.  

DOE Green Energy (OSTI)

This report is a preliminary assessment of the ignition and explosion potential in a depleted hydrocarbon reservoir from air cycling associated with compressed air energy storage (CAES) in geologic media. The study identifies issues associated with this phenomenon as well as possible mitigating measures that should be considered. Compressed air energy storage (CAES) in geologic media has been proposed to help supplement renewable energy sources (e.g., wind and solar) by providing a means to store energy when excess energy is available, and to provide an energy source during non-productive or low productivity renewable energy time periods. Presently, salt caverns represent the only proven underground storage used for CAES. Depleted natural gas reservoirs represent another potential underground storage vessel for CAES because they have demonstrated their container function and may have the requisite porosity and permeability; however reservoirs have yet to be demonstrated as a functional/operational storage media for compressed air. Specifically, air introduced into a depleted natural gas reservoir presents a situation where an ignition and explosion potential may exist. This report presents the results of an initial study identifying issues associated with this phenomena as well as possible mitigating measures that should be considered.

Cooper, Paul W.; Grubelich, Mark Charles; Bauer, Stephen J.

2011-09-01T23:59:59.000Z

40

The imbibition process of waterflooding in naturally fractured reservoirs  

E-Print Network (OSTI)

This thesis presents procedures to properly simulate naturally fractured reservoirs using dual-porosity models. The main objectives of this work are to: (1) determine if the spontaneous imbibition can be simulated using a two phase CMG simulator and validate it with laboratory experiments in the literature; (2) study the effect of countercurrent imbibition in field scale applications; and (3) develop procedures for using the dual-porosity to simulate fluid displacement in a naturally fractured reservoir. Reservoir simulation techniques, analytical solutions and numerical simulation for a two phase single and dual-porosity are used to achieve our objectives. Analysis of a single matrix block with an injector and a producer well connected by a single fracture is analyzed and compared with both two phase single and dual-porosity models. Procedures for obtaining reliable results when modeling a naturally fractured reservoir with a two phase dual-porosity model are presented and analyzed.

Huapaya Lopez, Christian A.

2003-12-01T23:59:59.000Z

Note: This page contains sample records for the topic "natural geological reservoir" from the National Library of EnergyBeta (NLEBeta).
While these samples are representative of the content of NLEBeta,
they are not comprehensive nor are they the most current set.
We encourage you to perform a real-time search of NLEBeta
to obtain the most current and comprehensive results.


41

EIA - Natural Gas Pipeline Network - Depleted Reservoir ...  

U.S. Energy Information Administration (EIA)

About U.S. Natural Gas Pipelines - Transporting Natural Gas based on data through 2007/2008 with selected updates

42

Carbon sequestration in natural gas reservoirs: Enhanced gas recovery and natural gas storage  

E-Print Network (OSTI)

as cushion gas for natural gas storage, Energy and Fuels,GAS RECOVERY AND NATURAL GAS STORAGE Curtis M. Oldenburgits operation as a natural gas storage reservoir. In this

Oldenburg, Curtis M.

2003-01-01T23:59:59.000Z

43

Fracture detection, mapping, and analysis of naturally fractured gas reservoirs using seismic technology. Final report, November 1995  

SciTech Connect

Many basins in the Rocky Mountains contain naturally fractured gas reservoirs. Production from these reservoirs is controlled primarily by the shape, orientation and concentration of the natural fractures. The detection of gas filled fractures prior to drilling can, therefore, greatly benefit the field development of the reservoirs. The objective of this project was to test and verify specific seismic methods to detect and characterize fractures in a naturally fractured reservoir. The Upper Green River tight gas reservoir in the Uinta Basin, Northeast Utah was chosen for the project as a suitable reservoir to test the seismic technologies. Knowledge of the structural and stratigraphic geologic setting, the fracture azimuths, and estimates of the local in-situ stress field, were used to guide the acquisition and processing of approximately ten miles of nine-component seismic reflection data and a nine-component Vertical Seismic Profile (VSP). Three sources (compressional P-wave, inline shear S-wave, and cross-line, shear S-wave) were each recorded by 3-component (3C) geophones, to yield a nine-component data set. Evidence of fractures from cores, borehole image logs, outcrop studies, and production data, were integrated with the geophysical data to develop an understanding of how the seismic data relate to the fracture network, individual well production, and ultimately the preferred flow direction in the reservoir. The multi-disciplinary approach employed in this project is viewed as essential to the overall reservoir characterization, due to the interdependency of the above factors.

NONE

1995-10-01T23:59:59.000Z

44

Development geology of giant fields on Alaskan North Slope: Key to successful reservoir management  

SciTech Connect

The giant fields on the North Slope of Alaska (combined Permian-Triassic/Lisburne pools at Prudhoe Bay and the Kuparuk River field) produce approximately 2 million BOPD and contain about 30 billion bbl of oil in place. This production rate amounts to almost one-fourth of the US daily production. Because the reservoirs in these fields are complex and the stakes in efficient field management so high, the development geology of these fields presents a great challenge. The technical challenge of managing these fields lies in the fact that secondary and tertiary recovery projects have been initiated soon after start-up to ensure maximum recovery. Thus, the development geologist has to recommend primary development locations while formulating a reservoir description without knowing the full areal extent and heterogeneity of the reservoirs. To support the waterflood and enhanced oil recovery projects, permeability pathways and barriers have been identified using sedimentological, log, and engineering data. Because structure also plays an important role in controlling fluid pathways, the fault geometries, fracture patterns, and detailed structure are being mapped using two-dimensional and three-dimensional seismic, well, and log data. The management challenge of development work in these fields is keeping communications channels open among the development geoscience group and the reservoir, production, operations, and drilling engineers.

Kumar, N. (ARCO Alaska, Inc., Anchorage (USA))

1988-12-01T23:59:59.000Z

45

Dispersion measurement as a method of quantifying geologic characterization and defining reservoir heterogeneity. Final report  

Science Conference Proceedings (OSTI)

The main objective of this research project is to investigate dispersion as a method of quantifying geological characterization and defining reservoir heterogeneity in order to enhance crude oil recovery. The dispersion of flow of a reservoir rock (dispersion coefficient and dispersivity) was identified as one of the physical properties of a reservoir rock by measuring the mixing of two miscible fluids, one displacing the other in a porous medium. A rock was 100% saturated with a resident fluid and displaced by a miscible fluid of equal viscosity and equal density. Some specific experiments were performed with unequal densities. Produced fluid was analyzed by refractometer, nuclear reaction, electrical conductivity and X-ray scan. Several physical and flow characteristics were measured on the sand rock sample in order to establish correlations with the measured dispersion property. Absolute permeability, effective porosity, relative permeability, capillary pressure, the heterogeneity factor and electrical conductivity were used to better understand the flow system. Linear, transverse, 2-D and 3-D dispersions were measured and used to characterize the rock heterogeneity of the flow system. A new system of measuring dispersion was developed using a gas displacing gas system in a porous medium. An attempt was also made to determine the dispersion property of an actual reservoir from present day well log data on a producing well. 275 refs., 102 figs., 17 tabs.

Menzie, D.E.

1995-05-01T23:59:59.000Z

46

Carbon sequestration in natural gas reservoirs: Enhanced gas recovery and natural gas storage  

SciTech Connect

Natural gas reservoirs are obvious targets for carbon sequestration by direct carbon dioxide (CO{sub 2}) injection by virtue of their proven record of gas production and integrity against gas escape. Carbon sequestration in depleted natural gas reservoirs can be coupled with enhanced gas production by injecting CO{sub 2} into the reservoir as it is being produced, a process called Carbon Sequestration with Enhanced Gas Recovery (CSEGR). In this process, supercritical CO{sub 2} is injected deep in the reservoir while methane (CH{sub 4}) is produced at wells some distance away. The active injection of CO{sub 2} causes repressurization and CH{sub 4} displacement to allow the control and enhancement of gas recovery relative to water-drive or depletion-drive reservoir operations. Carbon dioxide undergoes a large change in density as CO{sub 2} gas passes through the critical pressure at temperatures near the critical temperature. This feature makes CO{sub 2} a potentially effective cushion gas for gas storage reservoirs. Thus at the end of the CSEGR process when the reservoir is filled with CO{sub 2}, additional benefit of the reservoir may be obtained through its operation as a natural gas storage reservoir. In this paper, we present discussion and simulation results from TOUGH2/EOS7C of gas mixture property prediction, gas injection, repressurization, migration, and mixing processes that occur in gas reservoirs under active CO{sub 2} injection.

Oldenburg, Curtis M.

2003-04-08T23:59:59.000Z

47

Geologic, geochemical, and geographic controls on NORM in produced water from Texas oil, gas, and geothermal reservoirs. Final report  

DOE Green Energy (OSTI)

Water from Texas oil, gas, and geothermal wells contains natural radioactivity that ranges from several hundred to several thousand Picocuries per liter (pCi/L). This natural radioactivity in produced fluids and the scale that forms in producing and processing equipment can lead to increased concerns for worker safety and additional costs for handling and disposing of water and scale. Naturally occurring radioactive materials (NORM) in oil and gas operations are mainly caused by concentrations of radium-226 ({sup 226}Ra) and radium-228 ({sup 228}Ra), daughter products of uranium-238 ({sup 238}U) and thorium-232 ({sup 232}Th), respectively, in barite scale. We examined (1) the geographic distribution of high NORM levels in oil-producing and gas-processing equipment, (2) geologic controls on uranium (U), thorium (Th), and radium (Ra) in sedimentary basins and reservoirs, (3) mineralogy of NORM scale, (4) chemical variability and potential to form barite scale in Texas formation waters, (5) Ra activity in Texas formation waters, and (6) geochemical controls on Ra isotopes in formation water and barite scale to explore natural controls on radioactivity. Our approach combined extensive compilations of published data, collection and analyses of new water samples and scale material, and geochemical modeling of scale Precipitation and Ra incorporation in barite.

Fisher, R.

1995-08-01T23:59:59.000Z

48

Improving Geologic and Engineering Models of Midcontinent Fracture and Karst-Modified Reservoirs Using New 3-D Seismic Attributes  

Science Conference Proceedings (OSTI)

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.

Susan Nissen; Saibal Bhattacharya; W. Lynn Watney; John Doveton

2009-03-31T23:59:59.000Z

49

Relevance of underground natural gas storage to geologic sequestration of carbon dioxide  

Science Conference Proceedings (OSTI)

The practice of underground natural gas storage (UNGS), which started in the USA in 1916, provides useful insight into the geologic sequestration of carbon dioxide--the dominant anthropogenic greenhouse gas released into the atmosphere. In many ways, UNGS is directly relevant to geologic CO{sub 2} storage because, like CO{sub 2}, natural gas (essentially methane) is less dense than water. Consequently, it will tend to rise to the top of any subsurface storage structure located below the groundwater table. By the end of 2001 in the USA, about 142 million metric tons of natural gas were stored underground in depleted oil and gas reservoirs and brine aquifers. Based on their performance, UNGS projects have shown that there is a safe and effective way of storing large volumes of gases in the subsurface. In the small number of cases where failures did occur (i.e., leakage of the stored gas into neighboring permeable layers), they were mainly related to improper well design, construction, maintenance, and/or incorrect project operation. In spite of differences in the chemical and physical properties of the gases, the risk-assessment, risk-management, and risk-mitigation issues relevant to UNGS projects are also pertinent to geologic CO{sub 2} sequestration.

Lippmann, Marcelo J.; Benson, Sally M.

2002-07-01T23:59:59.000Z

50

Geologic CO2 Sequestration  

NLE Websites -- All DOE Office Websites (Extended Search)

Geologic CO2 Sequestration Geologic CO2 Sequestration Geologic reservoirs offer promising option for long- term storage of captured CO 2 Accumulations of gases (including CO 2 ) in geologic reservoirs, by natural processes or through enhanced oil recovery operations, demonstrate that gas can be stored for long periods of time and provide insights to the efficacy and impacts of geological gas storage. Los Alamos scientists in the Earth and Environmental Sciences (EES) Division have been involved in geologic CO 2 storage research for over a decade. Research Highlights * Led first-ever US field test on CO 2 sequestration in depleted oil reservoirs * Participant in two Regional Carbon Sequestration Partnerships (Southwest Regional and Big Sky) * Part of the National Risk Assessment Partnership (NRAP) for CO

51

RMOTC - Geologic & Resivoir Data  

NLE Websites -- All DOE Office Websites (Extended Search)

Geologic & Reservoir Data Data Sets Online Data Rooms Geologic & Reservoir Data Hills surrounding RMOTC Testing Facility Over the years, the field has become very well...

52

Three Models for Waterflooding in a Naturally Fractured Petroleum Reservoir  

E-Print Network (OSTI)

Introduction. For the purposes of this paper a naturally fractured reservoir is a porous medium that has been fractured in a regular geometric fashion; the resulting medium consists of a collection of porous matrix blocks, each of which is quite small with respect to the size of the reservoir, essentially lling out the reservoir, and a set of thin fractures that separate the blocks. The fractures will be considered to be generated by either two or three families of parallel planes. Though the total volume in the fractures is very small in comparison to the total void volume in the porous blocks, the ow of uids in such a fractured reservoir is seriously aected by the existence of the fractures, since the resistance to ow in the fractures is much smaller than that in the blocks. Flow in the blocks will be described by means of the usual Darcy and conservation laws [17]. Flow in the fractures will also be described using Darcy's law; this implies that the fractures will be t

Jim Douglas, Jr.

1987-01-01T23:59:59.000Z

53

Feasibility of optimizing recovery and reserves from a mature and geological complex multiple turbidite offshore California reservoir through the drilling and completion of a trilateral horizontal well. Annual report, September 1, 1995--December 31, 1996  

Science Conference Proceedings (OSTI)

The main objective of this project is to devise an effective re-development strategy to combat producibility problems related to the Repetto turbidite sequences of the Carpinteria Field. The lack of adequate reservoir characterization, high-water cut production, and scaling problems have in the past contributed to the field`s low productivity. To improve productivity and enhance recoverable reserves, the following specific goals were proposed: develop an integrated database of all existing data from work done by the former ownership group; expand reservoir drainage and reduce sand problems through horizontal well drilling and completion; operate and validate reservoir`s conceptual model by incorporating new data from the proposed trilateral well; and transfer methodologies employed in geologic modeling and drilling multilateral wells to other operators with similar reservoirs. A computer based data retrieval system was developed to convert hard copy documents containing production, well completion and well log data into easily accessible on-line format. To ascertain the geological framework of the reservoir, a thorough geological modeling and subsurface mapping of the Carpinteria field was developed. The model is now used to examine the continuity of the sands, characteristics of the sub-zones, nature of water influx and transition intervals in individual major sands. The geological model was then supplemented with a reservoir engineering study of spatial distribution of voidage in individual layers using the production statistics and pressure surveys. Efforts are continuing in selection of optimal location for drilling and completion of probing wells to obtain new data about reservoir pressure, in-situ saturation and merits of drilling a series of horizontal wells.

Coombs, S.; Edwards, E.; Fleckenstein, W.; Ershaghi, I.; Sobbi, F.; Coombs, S.

1998-07-01T23:59:59.000Z

54

Overview of geologic storage of natural gas with an emphasis on assessing the feasibility of storing hydrogen.  

DOE Green Energy (OSTI)

In many regions across the nation geologic formations are currently being used to store natural gas underground. Storage options are dictated by the regional geology and the operational need. The U.S. Department of Energy (DOE) has an interest in understanding theses various geologic storage options, the advantages and disadvantages, in the hopes of developing an underground facility for the storage of hydrogen as a low cost storage option, as part of the hydrogen delivery infrastructure. Currently, depleted gas/oil reservoirs, aquifers, and salt caverns are the three main types of underground natural gas storage in use today. The other storage options available currently and in the near future, such as abandoned coal mines, lined hard rock caverns, and refrigerated mined caverns, will become more popular as the demand for natural gas storage grows, especially in regions were depleted reservoirs, aquifers, and salt deposits are not available. The storage of hydrogen within the same type of facilities, currently used for natural gas, may add new operational challenges to the existing cavern storage industry, such as the loss of hydrogen through chemical reactions and the occurrence of hydrogen embrittlement. Currently there are only three locations worldwide, two of which are in the United States, which store hydrogen. All three sites store hydrogen within salt caverns.

Lord, Anna Snider

2009-09-01T23:59:59.000Z

55

U.S. Natural Gas Plant Liquids, New Reservoir Discoveries in...  

Gasoline and Diesel Fuel Update (EIA)

Liquids, New Reservoir Discoveries in Old Fields (Million Barrels) U.S. Natural Gas Plant Liquids, New Reservoir Discoveries in Old Fields (Million Barrels) Decade Year-0 Year-1...

56

New Mexico Dry Natural Gas New Reservoir Discoveries in Old Fields...  

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

New Reservoir Discoveries in Old Fields (Billion Cubic Feet) New Mexico Dry Natural Gas New Reservoir Discoveries in Old Fields (Billion Cubic Feet) Decade Year-0 Year-1 Year-2...

57

EIA - AEO2010 -Importance of low-permeability natural gas reservoirs  

Gasoline and Diesel Fuel Update (EIA)

Importance of low-permeability natural gas reservoirs Importance of low-permeability natural gas reservoirs Annual Energy Outlook 2010 with Projections to 2035 Importance of low-permeability natural gas reservoirs Introduction Production from low-permeability reservoirs, including shale gas and tight gas, has become a major source of domestic natural gas supply. In 2008, low-permeability reservoirs accounted for about 40 percent of natural gas production and about 35 percent of natural gas consumption in the United States. Permeability is a measure of the rate at which liquids and gases can move through rock. Low-permeability natural gas reservoirs encompass the shale, sandstone, and carbonate formations whose natural permeability is roughly 0.1 millidarcies or below. (Permeability is measured in “darcies.”)

58

Reserve growth through geological characterization of heterogeneous reservoirs - an example from mud-rich submarine fan reservoirs of Permian Spraberry Trend, west Texas  

SciTech Connect

Tight, naturally fractured Permian submarine fan reservoirs in the Midland basin contained more than 10.5 billion bbl of oil at discovery. Ultimate recovery is estimated to average 7% of the original oil in place. At abandonment 4 billion bbl of nonresidual mobile oil will remain in untapped or poorly drained reservoir compartments. This unproduced mobile oil is the target for Spraberry reserve growth through strategic infill drilling. Mid-fan facies of three separate submarine fans are productive in the Shackelford and Preston waterflood units (SPWU) in the central Spraberry Trend. Braided to meandering paleodip-oriented channels are flanked by levees which grade into upward-coarsening, unconfined distal fan sediment. Facies boundaries compartmentalize the reservoir, providing for interwell, stratigraphic entrapment of oil. Field-wide heterogeneity is pronounced. Stacking of channels in the upper Spraberry in the eastern half of the SPWU results in a dip-oriented belt of better reservoir quality. Wells completed in this axis have produced two to six times the amount of oil produced from wells located off of the depo-axis. Although fractures are important in early production, the contribution of matrix porosity is critical throughout the life of the reservoir. Current economics dictate that reserve growth might best be attained by siting new strategic infill wells in depositional axes and by selective recompletions of existing wells in areas of poorer reservoir quality for bypassed oil in undrained reservoir compartments.

Tyler, N.; Gholston, J.C.

1987-05-01T23:59:59.000Z

59

ESS 2012 Peer Review - CAES Geo Performance for Natural Gas and Salt Reservoirs and TMH Response of GSFs - Payton Gardner, SNL  

Energy.gov (U.S. Department of Energy (DOE)) Indexed Site

CAES Geo Performance CAES Geo Performance for Natural Gas and Salt Reservoirs, Thermal-Mechanical- Hydraulic Response of Geological Storage Formations for CAES 27 September 2012 SJ Bauer, M Martinez, W. Payton Gardner, J Holland 2 CAES Geo Performance for Natural Gas and Salt Reservoirs / Thermal-Mechanical-Hydraulic (T-M-H) Response of Geological Storage Formations for CAES  Problem: Siting of CAES facilities may be limited by specific geologic conditions  Opportunity: Fundamental understanding of T-M-H will enable/extend CAES siting potential throughout the US 3 Images taken from: http://www.rwe.com/ 1. CAES in Mined Salt Caverns  Model large scale salt cavern response to air pressure cycling  Experimentally evaluate thermal cycling effect on domal salt

60

Natural CO2 Reservoirs on the Colorado Plateau … Candidates for CO2 Sequestration  

NLE Websites -- All DOE Office Websites (Extended Search)

CO CO 2 Reservoirs on the Colorado Plateau and Southern Rocky Mountains: Candidates for CO 2 Sequestration. R. Allis (nrugs.rallis@state.ut.us; 801-537-3301) T. Chidsey (nrugs.tchidsey@state.ut.us; 801-537-3364) W. Gwynn (nrugs.wgwynn@state.ut.us; 801-537-3366) C. Morgan (nrugs.cmorgan@state.ut.us; 801-537-3370) Utah Geological Survey P.O. Box 146100 Salt Lake City, UT 84114 S. White (s.white@irl.cri.nz; 64-4-569-0000) Industrial Research Ltd. P.O. Box 31-310 Lower Hutt, New Zealand M. Adams (madams@egi.utah.edu; 801-585-7784) J. Moore (jmoore@egi.utah.edu; 801-585-6931) Energy and Geoscience Institute, 427 Wakara Way, Suite 300 Salt Lake City, UT84107 Abstract Numerous natural accumulations of CO 2 -dominant gases have been discovered as a result of

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61

Joule-Thomson Cooling Due to CO2 Injection into Natural Gas Reservoirs  

E-Print Network (OSTI)

as cushion gas for natural gas storage, Energy & Fuels, 17(super-cushion gas for natural gas storage (Oldenburg, 2003).storage of carbon dioxide in depleted natural gas reservoirs

Oldenburg, Curtis M.

2006-01-01T23:59:59.000Z

62

Relevance of underground natural gas storage to geologic sequestration of carbon dioxide  

E-Print Network (OSTI)

2002). U.S. Natural Gas Storage. http://www.eia.doe.gov/oil_OF UNDERGROUND NATURAL GAS STORAGE TO GEOLOGIC SEQUESTRATIONof underground natural gas storage (UNGS), which started in

Lippmann, Marcelo J.; Benson, Sally M.

2002-01-01T23:59:59.000Z

63

Rock Physics-Based Carbonate Reservoir Pore Type Evaluation by Combining Geological, Petrophysical and Seismic Data  

E-Print Network (OSTI)

Pore type variations account for complex velocity-porosity relationship and intensive permeability heterogeneity and consequently low oil and gas recovery in carbonate reservoir. However, it is a challenge for geologist and geophysicist to quantitatively estimate the influences of pore type complexity on velocity variation at a given porosity and porosity-permeability relationship. A new rock physics-based integrated approach in this study was proposed to quantitatively characterize the diversity of pore types and its influences on wave propagation in carbonate reservoir. Based on above knowledge, permeability prediction accuracy from petrophysical data can be improved compared to conventional approach. Two carbonate reservoirs with different reservoir features, one is a shallow carbonate reservoir with average high porosity (>10%) and another one is a supper-deep carbonate reservoir with average low porosity (Permian basin, West Texas. Meanwhile, the complex paleokarst system is explained by using a carbonate platform hydrological model, similar to modern marine hydrological environments within carbonate islands. How to evaluate carbonate reservoir permeability heterogeneity from 3D seismic data has been a dream for reservoir geoscientists, which is a key factor to optimize reservoir development strategy and enhance reservoir recovery. A two-step seismic inversions approach by integrating angle-stack seismic data and rock physics model is proposed to characterize pore-types complexity and further to identify the relative high permeability gas-bearing zones in low porosity reservoir (< 5%) using ChangXing super-deep carbonate reservoir as an example. Compared to the conventional permeability calculation method by best-fit function between porosity and permeability, the results in this study demonstrate that gas zones and non-gas zones in low porosity reservoir can be differentiated by using above integrated permeability characterization method.

Dou, Qifeng

2011-05-01T23:59:59.000Z

64

EOS7C Version 1.0: TOUGH2 Module for Carbon Dioxide or Nitrogen in Natural Gas (Methane) Reservoirs  

E-Print Network (OSTI)

as cushion gas for natural gas storage, Energy&Fuels ,2 as a cushion gas for natural gas storage can be found inin natural gas reservoirs and gas storage reservoirs (

Oldenburg, Curtis M.; Moridis, George J.; Spycher, Nicholas; Pruess, Karsten

2004-01-01T23:59:59.000Z

65

Natural and industrial analogues for release of CO2 from storage reservoirs: Identification of features, events, and processes and lessons learned  

E-Print Network (OSTI)

reservoirs and natural gas storage facilities, respectively,reservoirs and natural gas storage facilities. Nonetheless,USA The Yaggy natural gas storage facility is located seven

Lewicki, Jennifer L.; Birkholzer, Jens; Tsang, Chin-Fu

2006-01-01T23:59:59.000Z

66

Importance of Low Permeability Natural Gas Reservoirs (released in AEO2010)  

Reports and Publications (EIA)

Production from low-permeability reservoirs, including shale gas and tight gas, has become a major source of domestic natural gas supply. In 2008, low-permeability reservoirs accounted for about 40 percent of natural gas production and about 35 percent of natural gas consumption in the United States. Permeability is a measure of the rate at which liquids and gases can move through rock. Low-permeability natural gas reservoirs encompass the shale, sandstone, and carbonate formations whose natural permeability is roughly 0.1 millidarcies or below. (Permeability is measured in darcies.)

Information Center

2010-05-11T23:59:59.000Z

67

Secondary natural gas recovery: Targeted applications for infield reserve growth in midcontinent reservoirs, Boonsville Field, Fort Worth Basin, Texas. Topical report, May 1993--June 1995  

SciTech Connect

The objectives of this project are to define undrained or incompletely drained reservoir compartments controlled primarily by depositional heterogeneity in a low-accommodation, cratonic Midcontinent depositional setting, and, afterwards, to develop and transfer to producers strategies for infield reserve growth of natural gas. Integrated geologic, geophysical, reservoir engineering, and petrophysical evaluations are described in complex difficult-to-characterize fluvial and deltaic reservoirs in Boonsville (Bend Conglomerate Gas) field, a large, mature gas field located in the Fort Worth Basin of North Texas. The purpose of this project is to demonstrate approaches to overcoming the reservoir complexity, targeting the gas resource, and doing so using state-of-the-art technologies being applied by a large cross section of Midcontinent operators.

Hardage, B.A.; Carr, D.L.; Finley, R.J.; Tyler, N.; Lancaster, D.E.; Elphick, R.Y.; Ballard, J.R.

1995-07-01T23:59:59.000Z

68

Mercury Contents of Natural Thermal and Mineral Fluids, In- U.S. Geological  

Open Energy Info (EERE)

Mercury Contents of Natural Thermal and Mineral Fluids, In- U.S. Geological Mercury Contents of Natural Thermal and Mineral Fluids, In- U.S. Geological Survey Professional Paper 713 Jump to: navigation, search OpenEI Reference LibraryAdd to library Book Section: Mercury Contents of Natural Thermal and Mineral Fluids, In- U.S. Geological Survey Professional Paper 713 Abstract Abstract unavailable. Authors D.E. White, M.E. Hinkle and I. Barnes Published U.S. Government Printing Office, 1970 DOI Not Provided Check for DOI availability: http://crossref.org Online Internet link for Mercury Contents of Natural Thermal and Mineral Fluids, In- U.S. Geological Survey Professional Paper 713 Citation D.E. White,M.E. Hinkle,I. Barnes. 1970. Mercury Contents of Natural Thermal and Mineral Fluids, In- U.S. Geological Survey Professional Paper 713.

69

Maximizing Storage Rate and Capacity and Insuring the Environmental Integrity of Carbon Dioxide Sequestration in Geological Reservoirs  

Science Conference Proceedings (OSTI)

Maximizing Storage Rate and Capacity and Insuring the Environmental Integrity of Carbon Dioxide Sequestration in Geological Formations The U.S. and other countries may enter into an agreement that will require a significant reduction in CO2 emissions in the medium to long term. In order to achieve such goals without drastic reductions in fossil fuel usage, CO2 must be removed from the atmosphere and be stored in acceptable reservoirs. The research outlined in this proposal deals with developing a methodology to determine the suitability of a particular geologic formation for the long-term storage of CO2 and technologies for the economical transfer and storage of CO2 in these formations. A novel well-logging technique using nuclear-magnetic resonance (NMR) will be developed to characterize the geologic formation including the integrity and quality of the reservoir seal (cap rock). Well-logging using NMR does not require coring, and hence, can be performed much more quickly and efficiently. The key element in the economical transfer and storage of the CO2 is hydraulic fracturing the formation to achieve greater lateral spreads and higher throughputs of CO2. Transport, compression, and drilling represent the main costs in CO2 sequestration. The combination of well-logging and hydraulic fracturing has the potential of minimizing these costs. It is possible through hydraulic fracturing to reduce the number of injection wells by an order of magnitude. Many issues will be addressed as part of the proposed research to maximize the storage rate and capacity and insure the environmental integrity of CO2 sequestration in geological formations. First, correlations between formation properties and NMR relaxation times will be firmly established. A detailed experimental program will be conducted to determine these correlations. Second, improved hydraulic fracturing models will be developed which are suitable for CO2 sequestration as opposed to enhanced oil recovery (EOR). Although models that simulate the fracturing process exist, they can be significantly improved by extending the models to account for nonsymmetric, nonplanar fractures, coupling the models to more realistic reservoir simulators, and implementing advanced multiphase flow models for the transport of proppant. Third, it may be possible to deviate from current hydraulic fracturing technology by using different proppants (possibly waste materials that need to be disposed of, e.g., asbestos) combined with different hydraulic fracturing carrier fluids (possibly supercritical CO2 itself). Because current technology is mainly aimed at enhanced oil recovery, it may not be ideally suited for the injection and storage of CO2. Finally, advanced concepts such as increasing the injectivity of the fractured geologic formations through acidization with carbonated water will be investigated. Saline formations are located through most of the continental United States. Generally, where saline formations are scarce, oil and gas reservoirs and coal beds abound. By developing the technology outlined here, it will be possible to remove CO2 at the source (power plants, industry) and inject it directly into nearby geological formations, without releasing it into the atmosphere. The goal of the proposed research is to develop a technology capable of sequestering CO2 in geologic formations at a cost of US $10 per ton.

L.A. Davis; A.L. Graham; H.W. Parker; J.R. Abbott; M.S. Ingber; A.A. Mammoli; L.A. Mondy; Quanxin Guo; Ahmed Abou-Sayed

2005-12-07T23:59:59.000Z

70

Oklahoma Dry Natural Gas New Reservoir Discoveries in Old Fields (Billion  

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

New Reservoir Discoveries in Old Fields (Billion Cubic Feet) New Reservoir Discoveries in Old Fields (Billion Cubic Feet) Oklahoma Dry Natural Gas New Reservoir Discoveries in Old Fields (Billion Cubic Feet) Decade Year-0 Year-1 Year-2 Year-3 Year-4 Year-5 Year-6 Year-7 Year-8 Year-9 1970's 96 108 95 1980's 99 77 208 329 327 163 398 242 163 146 1990's 437 259 110 108 79 53 66 84 42 37 2000's 42 52 18 13 9 48 12 56 85 178 2010's 1 18 - = No Data Reported; -- = Not Applicable; NA = Not Available; W = Withheld to avoid disclosure of individual company data. Release Date: 8/1/2013 Next Release Date: 8/1/2014 Referring Pages: Dry Natural Gas New Reservoir Discoveries in Old Fields Oklahoma Dry Natural Gas Proved Reserves Dry Natural Gas New Reservoir Discoveries in Old Fields

71

Geological control on the reservoir characteristics of Olkaria West Geothermal Field, Kenya  

SciTech Connect

The reservoir of the West Olkaria Geothermal Field is hosted within tuffs and the reservoir fluid is characterized by higher concentrations of reservoir CO{sub 2} (10,000-100,000 mg/kg) but lower chloride concentrations of about 200 mg/kg than the East and North East Fields. The West Field is in the outflow and main recharge area of the Olkaria geothermal system. Permeability is generally low in the West Field and its distribution is strongly controlled by the structures. Fault zones show higher permeability with wells drilled within the structures havin larger total mass outputs. However, N-S and NW-SE faults are mainly channels for cold water downflow into the reservoir. Well feeder zones occur mostly at lava-tuff contacts; within fractured lava flows and at the contacts of intrusives and host rocks.

Omenda, Peter A.

1994-01-20T23:59:59.000Z

72

Depositional setting and reservoir geology of Kuparuk River oil field, North Slope, Alaska  

SciTech Connect

The Kuparuk River field is located approximately 20 mi (32 km) west of the Prudhoe Bay field and produces from the Lower Cretaceous Kuparuk River formation. The lower member of the Kuparuk is a sequence of interbedded sandstone, siltstone, and mudstone. Individual sandstone beds in the lower member are up to 5 ft (1.5 m) thick and consist of fine-grained, well-sorted quartzarenite. The basal part of the lower member contains five sandstone-rich cycles that prograde to the southeast. Each individual cycle strikes northeast-southwest and is up to 80 ft (254 m) thick, 40 mi (64 km) long, and 15 mi (25 km) wide. The lower member sandstones are interpreted to be storm deposits derived from a northerly source and deposited on a broad marine shelf. The upper member was deposited on an erosional unconformity and contains two sandstone intervals. These sandstone intervals are quartzose, glauconitic, very fine to coarse grained, poorly to moderately sorted, and intensely bioturbated. Both upper member sandstones are interpreted to have been deposited as subtidal sand bodies. The upper and lower member sandstones have similar average porosities (23%), but the average permeability of upper member sandstone is considerably higher than the average permeability of the lower member. Natural fractures in siderite-demented zones enhance the permeability of the upper member sandstone. Reservoir performance indicates that permeability is greatest in a north-south direction in upper member sandstones, and that a north-south directional permeability may also exist in lower member sandstone. North-south-oriented line-drive waterflood patterns will be utilized in areas where a north-south directional permeability is suspected.

Paris, C.E.; Masterson, D.W.

1985-04-01T23:59:59.000Z

73

Geological aspects of drilling horizontal wells in steam flood reservoirs, west side, southern San Joaquin Valley, California  

Science Conference Proceedings (OSTI)

Shell Western E P Inc. has drilled 11 horizontal wells in four mature steam floods in the Coalinga, South Belridge, and Midway-Sunset fields. Two medium radius wells are producing from the Pliocene Etchegoin Formation in Coalinga. One medium radius well is producing from the Pleistocene Tulare Formation in South Belridge field. Three short radius and five medium radius wells are producing from the upper Miocene, Sub-Hoyt and Potter sands in Midway-Sunset field. Horizontal wells at the base of these reservoirs and/or structurally downdip near the oil-water contact are ideally suited to take advantage of the gravity drainage production mechanism. Reservoir studies and production experience have shown these horizontal wells should increase reserves, improve recovery efficiency, improve the oil-steam ratio, and improve project profitability. Geological considerations of targeting the wells vary between fields because of the different depositional environments and resulting reservoir characteristics. The thin sands and semicontinuous shales in the Tulare Formation and the Etchegoin Formation require strict structural control on the top and base of the target sand. In the Sub-Hoyt and Potter sands, irregularities of the oil-water contact and sand and shale discontinuities must be understood. Logging and measurement while drilling provide geosteering capability in medium radius wells. Teamwork between all engineering disciplines and drilling and producing operations has been critical to horizontal well success.

Crough, D.D.; Holman, M.L.; Sande, J.J. (Shell Western E P Inc., Bakersfield, CA (United States))

1994-04-01T23:59:59.000Z

74

Advanced Reservoir Characterization and Evaluation of CO(2) Gravity Drainage in the Naturally Fractured Spraberry Reservoir  

SciTech Connect

Progress has been made in the area of laboratory analysis of Spraberry oil/brine/rock interactions during this quarter. Water imbibition experiments were conducted under ambient conditions, using cleaned Spraberry cores, synthetic Spraberry reservoir brine, and Spraberry oil. It has been concluded that the Spraberry reservoir cores are weakly water-wet. The average Amott wettability index to water is about 0.55. The average oil recovery due to spontaneous water imbibition is about 50% of original oil in place.

Schechter, David

1996-12-01T23:59:59.000Z

75

OPTIMIZATION OF INFILL DRILLING IN NATURALLY-FRACTURED TIGHT-GAS RESERVOIRS  

Science Conference Proceedings (OSTI)

A major goal of industry and the U.S. Department of Energy (DOE) fossil energy program is to increase gas reserves in tight-gas reservoirs. Infill drilling and hydraulic fracture stimulation in these reservoirs are important reservoir management strategies to increase production and reserves. Phase II of this DOE/cooperative industry project focused on optimization of infill drilling and evaluation of hydraulic fracturing in naturally-fractured tight-gas reservoirs. The cooperative project involved multidisciplinary reservoir characterization and simulation studies to determine infill well potential in the Mesaverde and Dakota sandstone formations at selected areas in the San Juan Basin of northwestern New Mexico. This work used the methodology and approach developed in Phase I. Integrated reservoir description and hydraulic fracture treatment analyses were also conducted in the Pecos Slope Abo tight-gas reservoir in southeastern New Mexico and the Lewis Shale in the San Juan Basin. This study has demonstrated a methodology to (1) describe reservoir heterogeneities and natural fracture systems, (2) determine reservoir permeability and permeability anisotropy, (3) define the elliptical drainage area and recoverable gas for existing wells, (4) determine the optimal location and number of new in-fill wells to maximize economic recovery, (5) forecast the increase in total cumulative gas production from infill drilling, and (6) evaluate hydraulic fracture simulation treatments and their impact on well drainage area and infill well potential. Industry partners during the course of this five-year project included BP, Burlington Resources, ConocoPhillips, and Williams.

Lawrence W. Teufel; Her-Yuan Chen; Thomas W. Engler; Bruce Hart

2004-05-01T23:59:59.000Z

76

MathematicalGeology, Vol. 11,No. I,1979 Modeling and Optimizing a Gas-Water Reservoir  

E-Print Network (OSTI)

Recovery with waterflooding'*- Mark E.Johnson,2EllisA. Mona&: and Michael S. Watermad Accepted practice the optimal production strategy. Essentially, this strategy is to refrain from waterflooding until the minimum strategy to be optimal. THE GAS-WATERFLOOD RESERVOIR MODEL The mathematical details of the gas-waterflood

Waterman, Michael S.

77

Integrated Reflection Seismic Monitoring and Reservoir Modeling for Geologic CO2 Sequestration  

Science Conference Proceedings (OSTI)

The US DOE/NETL CCS MVA program funded a project with Fusion Petroleum Technologies Inc. (now SIGMA) to model the proof of concept of using sparse seismic data in the monitoring of CO{sub 2} injected into saline aquifers. The goal of the project was to develop and demonstrate an active source reflection seismic imaging strategy based on deployment of spatially sparse surface seismic arrays. The primary objective was to test the feasibility of sparse seismic array systems to monitor the CO{sub 2} plume migration injected into deep saline aquifers. The USDOE/RMOTC Teapot Dome (Wyoming) 3D seismic and reservoir data targeting the Crow Mountain formation was used as a realistic proxy to evaluate the feasibility of the proposed methodology. Though the RMOTC field has been well studied, the Crow Mountain as a saline aquifer has not been studied previously as a CO{sub 2} sequestration (storage) candidate reservoir. A full reprocessing of the seismic data from field tapes that included prestack time migration (PSTM) followed by prestack depth migration (PSDM) was performed. A baseline reservoir model was generated from the new imaging results that characterized the faults and horizon surfaces of the Crow Mountain reservoir. The 3D interpretation was integrated with the petrophysical data from available wells and incorporated into a geocellular model. The reservoir structure used in the geocellular model was developed using advanced inversion technologies including Fusion's ThinMAN{trademark} broadband spectral inversion. Seal failure risk was assessed using Fusion's proprietary GEOPRESS{trademark} pore pressure and fracture pressure prediction technology. CO{sub 2} injection was simulated into the Crow Mountain with a commercial reservoir simulator. Approximately 1.2MM tons of CO{sub 2} was simulated to be injected into the Crow Mountain reservoir over 30 years and subsequently let 'soak' in the reservoir for 970 years. The relatively small plume developed from this injection was observed migrating due to gravity to the apexes of the double anticline in the Crow Mountain reservoir of the Teapot dome. Four models were generated from the reservoir simulation task of the project which included three saturation models representing snapshots at different times during and after simulated CO{sub 2} injection and a fully saturated CO{sub 2} fluid substitution model. The saturation models were used along with a Gassmann fluid substitution model for CO{sub 2} to perform fluid volumetric substitution in the Crow Mountain formation. The fluid substitution resulted in a velocity and density model for the 3D volume at each saturation condition that was used to generate a synthetic seismic survey. FPTI's (Fusion Petroleum Technologies Inc.) proprietary SeisModelPRO{trademark} full acoustic wave equation software was used to simulate acquisition of a 3D seismic survey on the four models over a subset of the field area. The simulated acquisition area included the injection wells and the majority of the simulated plume area.

John Rogers

2011-12-31T23:59:59.000Z

78

NETL: Carbon Storage - Geologic Storage  

NLE Websites -- All DOE Office Websites (Extended Search)

Geologic Storage Geologic Storage Carbon Storage Geologic Storage Focus Area Geologiccarbon dioxide (CO2) storage involves the injection of supercritical CO2 into deep geologic formations (injection zones) overlain by competent sealing formations and geologic traps that will prevent the CO2 from escaping. Current research and field studies are focused on developing better understanding 11 major types of geologic storage reservoir classes, each having their own unique opportunities and challenges. Understanding these different storage classes provides insight into how the systems influence fluids flow within these systems today, and how CO2 in geologic storage would be anticipated to flow in the future. The different storage formation classes include: deltaic, coal/shale, fluvial, alluvial, strandplain, turbidite, eolian, lacustrine, clastic shelf, carbonate shallow shelf, and reef. Basaltic interflow zones are also being considered as potential reservoirs. These storage reservoirs contain fluids that may include natural gas, oil, or saline water; any of which may impact CO2 storage differently. The following summarizes the potential for storage and the challenges related to CO2 storage capability for fluids that may be present in more conventional clastic and carbonate reservoirs (saline water, and oil and gas), as well as unconventional reservoirs (unmineable coal seams, organic-rich shales, and basalts):

79

Geological and petrophysical characterization of the Ferron Sandstone for 3-D simulation of a fluvial-deltaic reservoir. Quarterly report, July 1--September 30, 1994  

Science Conference Proceedings (OSTI)

The objective of this project is to develop a comprehensive, interdisciplinary, and quantitative characterization of a fluvial-deltaic reservoir which will allow realistic inter-well and reservoir-scale modeling to be developed for improved oil-field development in similar reservoirs world-wide. The geological and petrophysical properties of the Cretaceous Ferron Sandstone in east-central Utah will be quantitatively determined. Both new and existing data will be integrated into a 3-D representation of spatial variations in porosity, storativity, and tensorial rock permeability at a scale appropriate for inter-well to regional-scale reservoir simulation. Results could improve reservoir management through proper infill and extension drilling strategies, reduction of economic risks, increased recovery from existing oil fields, and more reliable reserve calculations. Transfer of the project results to the petroleum industry is an integral component of the project.

Allison, M.L. [Utah Geological and Mineral Survey, Salt Lake City, UT (United States)

1994-10-30T23:59:59.000Z

80

Naturally fractured tight gas reservoir detection optimization. Annual report, September 1993--September 1994  

Science Conference Proceedings (OSTI)

This report is an annual summarization of an ongoing research in the field of modeling and detecting naturally fractured gas reservoirs. The current research is in the Piceance basin of Western Colorado. The aim is to use existing information to determine the most optimal zone or area of fracturing using a unique reaction-transport-mechanical (RTM) numerical basin model. The RTM model will then subsequently help map subsurface lateral and vertical fracture geometries. The base collection techniques include in-situ fracture data, remote sensing, aeromagnetics, 2-D seismic, and regional geologic interpretations. Once identified, high resolution airborne and spaceborne imagery will be used to verify the RTM model by comparing surficial fractures. If this imagery agrees with the model data, then a further investigation using a three-dimensional seismic survey component will be added. This report presents an overview of the Piceance Creek basin and then reviews work in the Parachute and Rulison fields and the results of the RTM models in these fields.

NONE

1994-10-01T23:59:59.000Z

Note: This page contains sample records for the topic "natural geological reservoir" from the National Library of EnergyBeta (NLEBeta).
While these samples are representative of the content of NLEBeta,
they are not comprehensive nor are they the most current set.
We encourage you to perform a real-time search of NLEBeta
to obtain the most current and comprehensive results.


81

Maximizing Storage Rate and Capacity and Insuring the Environmental Integrity of Carbon Dioxide Sequestration in Geological Reservoirs  

NLE Websites -- All DOE Office Websites (Extended Search)

Maximizing Storage Rate and Capacity and Insuring the Environmental Maximizing Storage Rate and Capacity and Insuring the Environmental Integrity of Carbon dioxide Sequestration in Geological Reservoirs L. A. Davis Lorne.Davis@coe.ttu.edu Department of Petroleum Engineering A. L. Graham Alan.Graham@coe.ttu.edu H. W. Parker** Harry.Parker@coe.ttu.edu Department of Chemical Engineering Texas Tech University Lubbock, Texas 79409 M. S. Ingber ingber@me.unm.edu A. A. Mammoli mammoli@me.unm.edu Department of Mechanical Engineering University of New Mexico Albuquerque, New Mexico 87131 L. A. Mondy lamondy@engsci.sandia.gov Energetic and Multiphase Processes Department Sandia National Laboratories Albuquerque, New Mexico 87185-0834 Quanxin Guo quan@advantekinternational.com Ahmed Abou-Sayed a.abou-sayed@att.net

82

EIA - Natural Gas Pipeline Network - Aquifer Storage Reservoir ...  

U.S. Energy Information Administration (EIA)

About U.S. Natural Gas Pipelines - Transporting Natural Gas based on data through 2007/2008 with selected updates

83

Geological and petrophysical characterization of the Ferron Sandstone for 3-D simulation of a fluvial-deltaic reservoir. Annual report, October 1, 1995--September 30, 1996  

Science Conference Proceedings (OSTI)

The objective of the Ferron Sandstone project is to develop a comprehensive, interdisciplinary, quantitative characterization of a fluvial-deltaic reservoir to allow realistic inter-well and reservoir-scale models to be developed for improved oil-field development in similar reservoirs world-wide. Quantitative geological and petrophysical information on the Cretaceous Ferron Sandstone in east-central Utah was collected. Both new and existing data is being integrated into a three-dimensional model of spatial variations in porosity, storativity, and tensorial rock permeability at a scale appropriate for inter-well to regional-scale reservoir simulation. Simulation results could improve reservoir management through proper infill and extension drilling strategies, reduction of economic risks, increased recovery from existing oil fields, and more reliable reserve calculations. Transfer of the project results to the petroleum industry is an integral component of the project. This report covers research activities for fiscal year 1995-96, the third year of the project. Most work consisted of interpreting the large quantity of data collected over two field seasons. The project is divided into four tasks: (1) regional stratigraphic analysis, (2) case studies, (3) reservoirs models, and (4) field-scale evaluation of exploration strategies. The primary objective of the regional stratigraphic analysis is to provide a more detailed interpretation of the stratigraphy and gross reservoir characteristics of the Ferron Sandstone as exposed in outcrop. The primary objective of the case-studies work is to develop a detailed geological and petrophysical characterization, at well-sweep scale or smaller, of the primary reservoir lithofacies typically found in a fluvial-dominated deltaic reservoir.

Chidsey, T.C. Jr.

1997-05-01T23:59:59.000Z

84

SEISMIC DETERMINATION OF RESERVOIR HETEROGENEITY; APPLICATION TO THE CHARACTERIZATION OF HEAVY OIL RESERVOIRS  

SciTech Connect

The objective of the project is to examine how seismic and geologic data can be used to improve characterization of small-scale heterogeneity and their parameterization in reservoir models. The study is performed at West Coalinga Field in California. We continued our investigation on the nature of seismic reactions from heterogeneous reservoirs. We began testing our algorithm to infer parameters of object-based reservoir models from seismic data. We began integration of seismic and geologic data to determine the deterministic limits of conventional seismic data interpretation. Lastly, we began integration of seismic and geologic heterogeneity using stochastic models conditioned both on wireline and seismic data.

Matthias G. Imhof; James W. Castle

2003-11-01T23:59:59.000Z

85

INVESTIGATION OF EFFICIENCY IMPROVEMENTS DURING CO2 INJECTION IN HYDRAULICALLY AND NATURALLY FRACTURED RESERVOIRS  

Science Conference Proceedings (OSTI)

This report describes the work performed during the fourth year of the project, ''Investigating of Efficiency Improvements during CO{sub 2} Injection in Hydraulically and Naturally Fractured Reservoirs.'' The objective of this project is to perform unique laboratory experiments with artificially fractured cores (AFCs) and X-ray CT scanner to examine the physical mechanisms of bypassing in hydraulically fractured reservoirs (HFR) and naturally fractured reservoirs (NFR) that eventually result in more efficient CO{sub 2} flooding in heterogeneous or fracture-dominated reservoirs. In Chapter 1, we worked with DOE-RMOTC to investigate fracture properties in the Tensleep Formation at Teapot Dome Naval Reserve as part of their CO{sub 2} sequestration project. In Chapter 2, we continue our investigation to determine the primary oil recovery mechanism in a short vertically fractured core. Finally in Chapter 3, we report our numerical modeling efforts to develop compositional simulator with irregular grid blocks.

David S. Schechter

2005-04-27T23:59:59.000Z

86

Carbon sequestration in natural gas reservoirs: Enhanced gas recovery and natural gas storage  

E-Print Network (OSTI)

gas reservoirs for carbon sequestration and enhanced gasproduction and carbon sequestration, Society of Petroleumfeasibiilty of carbon sequestration with enhanced gas

Oldenburg, Curtis M.

2003-01-01T23:59:59.000Z

87

Significant test results, energy potential, and geology of some Gulf Coast geopressured-geothermal sandstone reservoirs  

Science Conference Proceedings (OSTI)

Geopressured-geothermal reservoir found in the northern Gulf of Mexico basin represent a large potential future energy resource. Three reservoirs in various stages of developmental testing are of current interest. Over a four-year testing period the Gladys McCall 1 (Cameron Parish, Louisiana) produced 27.3 million bbl of brine and 676 million scf of gas at an average rate of 20,000 bbl/day from perforations between 15,158 and 15,490 ft. This lower Miocene sandstone section forms part of a genetic unit of interconnected channel and point-bar sandstones deposited in a lower shelf environment. Pleasant Bayou 2 well (Brazoria County, Texas) is currently being flow-tested at 20,000 bbl/day and has a gas/brine ratio of approximately 23 scf/stb and a temperature of 291/degrees/F. An electric energy conversion system being set up here will test potential for electric generation from geopressured-geothermal energy. Superior Hulin 1 (Vermilion Parish, Louisiana) is a deep (21,549 ft) former gas well proposed to be completed as a geopressured-geothermal well. Initial log analysis indicates that a 570-ft thick sandstone, of probable submarine fan origin, may contain free gas in addition to solution gas and may thus represent an economically feasible geopressured-geothermal well. Gas-separated brine is disposed by subsurface injection into disposal wells. However, in areas where hydrocarbon fields with wells penetrating geopressured sands are present, hot brines could be injected into depleted hydrocarbon zones to aid secondary recovery.

John, C.J.; Stevenson, D.A.

1989-03-01T23:59:59.000Z

88

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

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.

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

2004-01-13T23:59:59.000Z

89

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

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.

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

2003-04-01T23:59:59.000Z

90

Impact of reservoir properties on mixing of inert cushion and natural gas in storage reservoirs.  

E-Print Network (OSTI)

??Underground natural gas storage is a process which effectively balances a variable demand market with a nearly constant supply of energy provided by the pipeline (more)

Srinivasan, Balaji S.

2006-01-01T23:59:59.000Z

91

CFD Modeling of Methane Production from Hydrate-Bearing Reservoir  

Science Conference Proceedings (OSTI)

Methane hydrate is being examined as a next-generation energy resource to replace oil and natural gas. The U.S. Geological Survey estimates that methane hydrate may contain more organic carbon the the world's coal, oil, and natural gas combined. To assist in developing this unfamiliar resource, the National Energy Technology Laboratory has undertaken intensive research in understanding the fate of methane hydrate in geological reservoirs. This presentation reports preliminary computational fluid dynamics predictions of methane production from a subsurface reservoir.

Gamwo, I.K.; Myshakin, E.M.; Warzinski, R.P.

2007-04-01T23:59:59.000Z

92

Geological and petrophysical characterization of the Ferron Sandstone for 3-D simulation of a fluvial-deltaic reservoir. Annual report, September 29, 1993--September 29, 1994  

Science Conference Proceedings (OSTI)

The objective of the Ferron Sandstone project is to develop a comprehensive, interdisciplinary, quantitative characterization of a fluvial-deltaic reservoir to allow realistic inter-well and reservoir-scale models to be developed for improved oil-field development in similar reservoirs world-wide. Quantitative geological and petrophysical information on the Cretaceous Ferron Sandstone in east-central Utah will be collected. Both new and existing data will be integrated into a three-dimensional model of spatial variations in porosity, storativity, and tensorial rock permeability at a scale appropriate for inter-well to regional-scale reservoir simulation. Simulation results could improve reservoir management through proper infill and extension drilling strategies, reduction of economic risks, increased recovery from existing oil fields, and more reliable reserve calculations. Transfer of the project results to the petroleum industry is an integral component of the project. This report covers research activities for fiscal year 1993-94, the first year of the project. Most work consisted of developing field methods and collecting large quantities of existing and new data. We also developed preliminary regional and case-study area interpretations. The project is divided into four tasks: (1) regional stratigraphic analysis, (2) case studies, (3) development of reservoirs models, and (4) field-scale evaluation of exploration strategies.

Allison, M.

1995-07-01T23:59:59.000Z

93

ESS 2012 Peer Review - CAES Geo Performance for Natural Gas and...  

Energy.gov (U.S. Department of Energy (DOE)) Indexed Site

between photos and header CAES Geo Performance for Natural Gas and Salt Reservoirs, Thermal-Mechanical- Hydraulic Response of Geological Storage Formations for CAES 27 September...

94

Designing cyclic pressure pulsing in naturally fractured reservoirs using an inverse looking recurrent neural network  

Science Conference Proceedings (OSTI)

In this paper, an inverse looking approach is presented to efficiently design cyclic pressure pulsing (huff 'n' puff) with N"2 and CO"2, which is an effective improved oil recovery method in naturally fractured reservoirs. A numerical flow simulation ... Keywords: Big Andy Field, CO2, Cyclic pressure pulsing, Huff 'n' puff, N2, Recurrent neural networks

E. Artun; T. Ertekin; R. Watson; B. Miller

2012-01-01T23:59:59.000Z

95

Natural and industrial analogues for release of CO2 from storage reservoirs: Identification of features, events, and processes and lessons learned  

E-Print Network (OSTI)

reservoirs and natural gas storage facilities. Nonetheless,USA The Yaggy natural gas storage facility is located sevenreservoirs and natural gas storage facilities, respectively,

Lewicki, Jennifer L.; Birkholzer, Jens; Tsang, Chin-Fu

2006-01-01T23:59:59.000Z

96

Geological controls on natural gas production in the Antrim Shale of the Michigan basin  

Science Conference Proceedings (OSTI)

The Antrim Shale (Devonian-Mississippian) is a prolific natural gas reservoir with distinctive source rock and reservoir characteristics. The Antrim is composed of two distinctive lithofacies: a black shale lithofacies having total organic carbon (TOC) values as high as 12% and a gray-green shale lithofacies having TOC values generally below 0.5 %. The black shale facies is the primary source bed and reservoir for natural gas. Based on Rock-Eval data the kerogen in the Antrim Shale is only marginally mature with respect to generation of liquid hydrocarbons. This in the range of 435{degree}C, vitrinite reflectance values are 0.41, and thermal alteration index (TAI) is 2. These data indicate a maximum burial temperature of approximately 60{degree}C in Otsego County, Michigan, the main play area. Although the thermal maturation level in this area is very low, the gas produced from the Antrim is internally sourced and thermogenic; this interpretation is based on the presence of trace amounts of high-gravity oil and a thermogenic isotopic signature of produced gas samples. The black shale facies in the Antrim contains significant authigenic silica and is more susceptible to fracturing compared to the carbonate-cemented gray-green shales facies. Extremely low gas permeability values (0.1 md) indicates that fractures serve as conduits for delivery of gas to the borehole. Most of the gas must be stored in the shale matrix porosity because total gas volume produced far exceeds fracture reservoir volume.

Dellapenna, T.M. (Western Michigan Univ., Kalamazoo (USA))

1990-05-01T23:59:59.000Z

97

U.S. Nonassociated Natural Gas, Wet After Lease Separation, New Reservoir  

Gasoline and Diesel Fuel Update (EIA)

Reservoir Discoveries in Old Fields (Billion Cubic Feet) Reservoir Discoveries in Old Fields (Billion Cubic Feet) U.S. Nonassociated Natural Gas, Wet After Lease Separation, New Reservoir Discoveries in Old Fields (Billion Cubic Feet) Decade Year-0 Year-1 Year-2 Year-3 Year-4 Year-5 Year-6 Year-7 Year-8 Year-9 1970's 2,373 1980's 2,279 2,809 3,155 2,745 2,482 2,712 1,666 1,401 1,640 2,139 1990's 2,242 1,321 1,481 1,767 3,404 1,884 2,871 2,268 2,022 1,841 2000's 2,211 2,420 1,421 1,529 1,147 1,164 1,132 1,171 858 2,487 2010's 1,515 1,100 - = No Data Reported; -- = Not Applicable; NA = Not Available; W = Withheld to avoid disclosure of individual company data. Release Date: 8/1/2013 Next Release Date: 8/1/2014 Referring Pages: Nonassociated Natural Gas New Reservoir Discoveries in Old Fields,

98

U.S. Natural Gas, Wet After Lease Separation New Reservoir Discoveries in  

Gasoline and Diesel Fuel Update (EIA)

New Reservoir Discoveries in Old Fields (Billion Cubic Feet) New Reservoir Discoveries in Old Fields (Billion Cubic Feet) U.S. Natural Gas, Wet After Lease Separation New Reservoir Discoveries in Old Fields (Billion Cubic Feet) Decade Year-0 Year-1 Year-2 Year-3 Year-4 Year-5 Year-6 Year-7 Year-8 Year-9 1970's 2,637 1980's 2,648 3,080 3,520 3,071 2,778 3,053 1,855 1,556 1,979 2,313 1990's 2,492 1,655 1,773 1,930 3,606 2,518 3,209 2,455 2,240 2,265 2000's 2,463 2,898 1,752 1,653 1,244 1,243 1,197 1,244 1,678 2,656 2010's 1,701 1,260 - = No Data Reported; -- = Not Applicable; NA = Not Available; W = Withheld to avoid disclosure of individual company data. Release Date: 8/1/2013 Next Release Date: 8/1/2014 Referring Pages: New Reservoir Discoveries in Old Fields of Natural Gas, Wet After

99

U.S. Dry Natural Gas New Reservoir Discoveries in Old Fields (Billion Cubic  

Gasoline and Diesel Fuel Update (EIA)

New Reservoir Discoveries in Old Fields (Billion Cubic Feet) New Reservoir Discoveries in Old Fields (Billion Cubic Feet) U.S. Dry Natural Gas New Reservoir Discoveries in Old Fields (Billion Cubic Feet) Decade Year-0 Year-1 Year-2 Year-3 Year-4 Year-5 Year-6 Year-7 Year-8 Year-9 1970's 3,301 4,579 2,566 1980's 2,577 2,998 3,419 2,965 2,686 2,960 1,771 1,499 1,909 2,243 1990's 2,412 1,604 1,724 1,866 3,480 2,452 3,110 2,382 2,162 2,196 2000's 2,368 2,800 1,694 1,610 1,206 1,208 1,155 1,188 1,622 2,598 2010's 1,668 1,227 - = No Data Reported; -- = Not Applicable; NA = Not Available; W = Withheld to avoid disclosure of individual company data. Release Date: 8/1/2013 Next Release Date: 8/1/2014 Referring Pages: Dry Natural Gas New Reservoir Discoveries in Old Fields

100

Pressure testing of a high temperature naturally fractured reservoir  

DOE Green Energy (OSTI)

Los Alamos National Laboratory has conducted a number of pumping and flow-through tests at the Hot Dry Rock (HDR) test site at Fenton Hill, New Mexico. These tests consisted of injecting fresh water at controlled rates up to 12 BPM (32 l/s) and surface pressures up to 7000 psi (48 MPa) into the HDR formation at depths from 10,000 to 13,180 feet (3050 to 4000 m). The formation is a naturally fractured granite at temperatures of about 250/sup 0/C. The matrix porosity is <1% and permeability is on the order of 1 nD. Hence most of the injected fluid is believed to move through fractures. There has been no evidence of fracture breakdown phenomena, and hence it is believed that preexisting joints in the formation are opened by fluid injection. Water losses during pumping are significant, most likely resulting from flow into secondary fractures intersecting the main fluid conducting paths. The pressure-time response observed in these tests can be interpreted in terms of non-isothermal, fracture-dominated flow. As the fluid pressure increases from small values to those comparable to fracturing pressures, the formation response changes from linear fracture flow to the highly nonlinear situation where fracture lift-off occurs. A numerical heat and mass flow model was used to match the observed pressure response. Good matches were obtained for pressure buildup and shut-in data by assigning pressure dependent fracture and leak-off permeabilities. 12 refs., 5 figs., 2 tabs.

Kelkar, S.M.; Zyvoloski, G.A.; Dash, Z.V.

1986-01-01T23:59:59.000Z

Note: This page contains sample records for the topic "natural geological reservoir" from the National Library of EnergyBeta (NLEBeta).
While these samples are representative of the content of NLEBeta,
they are not comprehensive nor are they the most current set.
We encourage you to perform a real-time search of NLEBeta
to obtain the most current and comprehensive results.


101

THE NATURAL THERMODYNAMIC STATE OF THE FLUIDS IN THE LOS AZUFRES GEOTHERMAL RESERVOIR  

DOE Green Energy (OSTI)

We have devised a simple method to assess the natural thermodynamic state of two-phase reservoirs. This is usually a complex task. The method is based on inferring sandface flowing pressures and enthalpies from production output (deliverability) curves, and then extrapolating to shutin conditions in the pressure-enthalpy plane. The method was applied to data from 10 wells of the Los Azufres geothermal field. Comparison of the results with measured pressures and temperatures showed that the method is reliable. We present detailed thermodynamic properties of the unperturbed reservoir fluid in the neighborhood of the wells studied, in tabular form. Moreover, we present a match to these results with a very simple model that allows reasonable estimates of natural thermodynamic conditions as functions of height above sea level. The present results have important implications for the assessment of the fluid reserves, which are suggested to be greater than previously thought.

Iglesias, E.R.; Arellano, V.M.; Gardias, A.

1985-01-22T23:59:59.000Z

102

Underground natural gas storage reservoir management: Phase 2. Final report, June 1, 1995--March 30, 1996  

SciTech Connect

Gas storage operators are facing increased and more complex responsibilities for managing storage operations under Order 636 which requires unbundling of storage from other pipeline services. Low cost methods that improve the accuracy of inventory verification are needed to optimally manage this stored natural gas. Migration of injected gas out of the storage reservoir has not been well documented by industry. The first portion of this study addressed the scope of unaccounted for gas which may have been due to migration. The volume range was estimated from available databases and reported on an aggregate basis. Information on working gas, base gas, operating capacity, injection and withdrawal volumes, current and non-current revenues, gas losses, storage field demographics and reservoir types is contained among the FERC Form 2, EIA Form 191, AGA and FERC Jurisdictional databases. The key elements of this study show that gas migration can result if reservoir limits have not been properly identified, gas migration can occur in formation with extremely low permeability (0.001 md), horizontal wellbores can reduce gas migration losses and over-pressuring (unintentionally) storage reservoirs by reinjecting working gas over a shorter time period may increase gas migration effects.

Ortiz, I.; Anthony, R.V.

1996-12-31T23:59:59.000Z

103

Modeling Wettability Alteration using Chemical EOR Processes in Naturally Fractured Reservoirs  

Science Conference Proceedings (OSTI)

The objective of our search is to develop a mechanistic simulation tool by adapting UTCHEM to model the wettability alteration in both conventional and naturally fractured reservoirs. This will be a unique simulator that can model surfactant floods in naturally fractured reservoir with coupling of wettability effects on relative permeabilities, capillary pressure, and capillary desaturation curves. The capability of wettability alteration will help us and others to better understand and predict the oil recovery mechanisms as a function of wettability in naturally fractured reservoirs. The lack of a reliable simulator for wettability alteration means that either the concept that has already been proven to be effective in the laboratory scale may never be applied commercially to increase oil production or the process must be tested in the field by trial and error and at large expense in time and money. The objective of Task 1 is to perform a literature survey to compile published data on relative permeability, capillary pressure, dispersion, interfacial tension, and capillary desaturation curve as a function of wettability to aid in the development of petrophysical property models as a function of wettability. The new models and correlations will be tested against published data. The models will then be implemented in the compositional chemical flooding reservoir simulator, UTCHEM. The objective of Task 2 is to understand the mechanisms and develop a correlation for the degree of wettability alteration based on published data. The objective of Task 3 is to validate the models and implementation against published data and to perform 3-D field-scale simulations to evaluate the impact of uncertainties in the fracture and matrix properties on surfactant alkaline and hot water floods.

Mojdeh Delshad; Gary A. Pope; Kamy Sepehrnoori

2007-09-30T23:59:59.000Z

104

Assistant Professor Quantitative Structural Geology or Geomechanics  

E-Print Network (OSTI)

/tectonics, hydrogeology, stable isotope geochemistry, environmental geology, sedimentology and stratigraphyAssistant Professor Quantitative Structural Geology or Geomechanics The Department of Geology structural geology with interest in the study of fractured reservoirs and geomechanics. The successful

Mohaghegh, Shahab

105

INVESTIGATION OF EFFICIENCY IMPROVEMENTS DURING CO2 INJECTION IN HYDRAULICALLY AND NATURALLY FRACTURED RESERVOIRS  

SciTech Connect

This report describes the work performed during the second year of the project, ''Investigating of Efficiency Improvements during CO{sub 2} Injection in Hydraulically and Naturally Fractured Reservoirs.'' The objective of this project is to perform unique laboratory experiments with artificial fractured cores (AFCs) and X-ray CT to examine the physical mechanisms of bypassing in HFR and NFR that eventually result in less efficient CO{sub 2} flooding in heterogeneous or fracture-dominated reservoirs. To achieve this objective, in this period we concentrated our effort on investigating the effect of CO{sub 2} injection rates in homogeneous and fractured cores on oil recovery and a strategy to mitigate CO{sub 2} bypassing in a fractured core.

David S. Schechter

2004-04-26T23:59:59.000Z

106

Natural Analogs for Geologic Storage of CO2: An Integrated Global Research Program  

NLE Websites -- All DOE Office Websites (Extended Search)

JAF21006.DOC JAF21006.DOC First National Conference on Carbon Sequestration U.S. Department of Energy National Energy Technology Laboratory May 15-17, 2001 Washington, D.C. Natural Analogs for Geologic Storage of CO 2 : An Integrated Global Research Program S. H. Stevens (sstevens@adv-res.com, (703) 528 8420) Advanced Resources International, Inc. 1110 N. Glebe Road, Suite 600 Arlington, VA USA 22201 703-528-8420 J. M. Pearce (jmpe@bgs.ac.uk, (0)115 9363 222) British Geological Survey Nottingham, NG12 5GG, United Kingdom. A. A. J. Rigg (a.rigg@petroleum.crc.org.au, 61-2-9490 8225) Australian Petroleum Cooperative Research Centre Sydney, NSW Australia ABSTRACT Coordinated research efforts are underway on three continents (North America, Europe,

107

Injection and Reservoir Hazard Management: Mechanical Deformation and Geochemical Alteration at the InSalah CO2 Storage Project  

NLE Websites -- All DOE Office Websites (Extended Search)

Injection and Reservoir Hazard Injection and Reservoir Hazard Management: Mechanical Deformation and Geochemical Alteration at the In Salah CO 2 Storage Project Background Safe and permanent storage of carbon dioxide (CO 2 ) in geologic reservoirs is critical to geologic sequestration. The In Salah Project (joint venture of British Petroleum (BP), Sonatrach, and StatoilHydro) has two fundamental goals: (1) 25-30 years of 9 billion cubic feet per year (bcfy) natural gas production from 8 fields in the Algerian

108

The effect of natural fracture characteristics on current analytical models for hydraulically fractured unconventional shale reservoirs.  

E-Print Network (OSTI)

??In recent years, the oil and gas industry has shifted its focus more towards unconventional shale reservoirs. It has become apparent that these reservoirs require (more)

Junor, Nathaniel T.

2013-01-01T23:59:59.000Z

109

Advanced Reservoir Characterization and Evaluation of CO{sub 2} Gravity Drainage in the Naturally Fractured Spraberry Trend Area  

Science Conference Proceedings (OSTI)

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.

Schechter, D.S.

1999-02-03T23:59:59.000Z

110

Advanced Reservoir Characterization and Evaluation of CO2 Gravity Drainage in the Naturally Fractured Spraberry Trend Area, Class III  

Science Conference Proceedings (OSTI)

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.

Knight, Bill; Schechter, David S.

2002-07-26T23:59:59.000Z

111

Tritium Transport at the Rulison Site, a Nuclear-stimulated Low-permeability Natural Gas Reservoir  

SciTech Connect

The U.S. Department of Energy (DOE) and its predecessor agencies conducted a program in the 1960s and 1970s that evaluated technology for the nuclear stimulation of low-permeability natural gas reservoirs. The second project in the program, Project Rulison, was located in west-central Colorado. A 40-kiltoton nuclear device was detonated 2,568 m below the land surface in the Williams Fork Formation on September 10, 1969. The natural gas reservoirs in the Williams Fork Formation occur in low permeability, fractured sandstone lenses interbedded with shale. Radionuclides derived from residual fuel products, nuclear reactions, and activation products were generated as a result of the detonation. Most of the radionuclides are contained in a cooled, solidified melt glass phase created from vaporized and melted rock that re-condensed after the test. Of the mobile gas-phase radionuclides released, tritium ({sup 3}H or T) migration is of most concern. The other gas-phase radionuclides ({sup 85}Kr, {sup 14}C) were largely removed during production testing in 1969 and 1970 and are no longer present in appreciable amounts. Substantial tritium remained because it is part of the water molecule, which is present in both the gas and liquid (aqueous) phases. The objectives of this work are to calculate the nature and extent of tritium contamination in the subsurface from the Rulison test from the time of the test to present day (2007), and to evaluate tritium migration under natural-gas production conditions to a hypothetical gas production well in the most vulnerable location outside the DOE drilling restriction. The natural-gas production scenario involves a hypothetical production well located 258 m horizontally away from the detonation point, outside the edge of the current drilling exclusion area. The production interval in the hypothetical well is at the same elevation as the nuclear chimney created by the detonation, in order to evaluate the location most vulnerable to tritium migration.

C. Cooper; M. Ye; J. Chapman

2008-04-01T23:59:59.000Z

112

Natural and Induced Fracture Diagnostics from 4-D VSP Low Permeability Gas Reservoirs  

SciTech Connect

Tight gas sand reservoirs generally contain thick gas-charged intervals that often have low porosity and very low permeability. Natural and induced fractures provide the only means of production. The objective of this work is to locate and characterize natural and induced fractures from analysis of scattered waves recorded on 4-D (time lapse) VSP data in order to optimize well placement and well spacing in these gas reservoirs. Using model data simulating the scattering of seismic energy from hydraulic fractures, we first show that it is possible to characterize the quality of fracturing based upon the amount of scattering. In addition, the picked arrival times of recorded microseismic events provide the velocity moveout for isolating the scattered energy on the 4-D VSP data. This concept is applied to a field dataset from the Jonah Field in Wyoming to characterize the quality of the induced hydraulic fractures. The time lapse (4D) VSP data from this field are imaged using a migration algorithm that utilizes shot travel time tables derived from the first breaks of the 3D VSPs and receiver travel time tables based on the microseismic arrival times and a regional velocity model. Four azimuthally varying shot tables are derived from picks of the first breaks of over 200 VSP records. We create images of the fracture planes through two of the hydraulically fractured wells in the field. The scattered energy shows correlation with the locations of the microseismic events. In addition, the azimuthal scattering is different from the azimuthal reflectivity of the reservoir, giving us more confidence that we have separated the scattered signal from simple formation reflectivity. Variation of the scattered energy along the image planes suggests variability in the quality of the fractures in three distinct zones.

Mark E. Willis; Daniel R. Burns; M. Nafi Toksoz

2008-09-30T23:59:59.000Z

113

Simulation studies to evaluate the effect of fracture closure on the performance of naturally fractured reservoirs. Annual report  

Science Conference Proceedings (OSTI)

The second year of this 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 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 have been conducted with a dual porosity simulator capable of simulating the performance of vertical and horizontal wells. Each simulation model has been initialized with properties typical of the Austin Chalk reservoir in Pearsall Field, Texas. During year one, simulations of both vertical and horizontal well performance were made assuming that fracture permeability was insensitive to pressure charge. The results confirmed that horizontal wells could increase both rate of oil recovery and total oil recovery from naturally fractured reservoirs. During the second year the performances of the same vertical and horizontal wells were evaluated with the assumption that fracture permeability was a function of reservoir pressure. This required repetition of most of the natural depletion cases simulated in year one while invoking the pressure-sensitive fracture permeability option. To investigate sensitivity to in situ stress, two stress conditions were simulated for each primary variable. The water injection cases, begun in year one, were extended to include most of the reservoir parameters investigated for natural depletion, including fracture permeability as a function of net stress and the use of horizontal wells. The results thus far confirm that pressure-sensitive fractures degrade well performance and that the degradation is reduced by water injection pressure maintenance. Furthermore, oil recovery can be significantly increased by water injection pressure maintenance.

Not Available

1992-11-01T23:59:59.000Z

114

Simulation studies to evaluate the effect of fracture closure on the performance of naturally fractured reservoirs. Annual report  

SciTech Connect

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.

Not Available

1991-10-01T23:59:59.000Z

115

Numerical Simulation of CO2 Sequestration in Natural CO2 Reservoirs on the Colorado Plateau  

NLE Websites -- All DOE Office Websites (Extended Search)

Simulation of CO Simulation of CO 2 Sequestration in Natural CO 2 Reservoirs on the Colorado Plateau Stephen P. White (S.White@irl.cri.nz, (64) 4 5690000) Graham J. Weir (G.Weir@irl.cri.nz, (64) 4 5690000) Warwick M. Kissling (W.Kissling@irl.cri.nz, (64) 4 5690000) Industrial Research Ltd. P.O. Box 31310 Lower Hutt, New Zealand Abstract This paper outlines the proposed research and summarizes pre-project work that forms a basis for a new research program on CO 2 sequestration in saline aquifers. The pre-project work considers storage and disposal of CO 2 several kilometers beneath the surface in generic aquifers and demonstrates the use of reactive chemical transport modeling to simulate mineral sequestration of CO 2. The current research project applies these techniques to particular saline

116

Hydrothermal Reservoirs | Open Energy Information  

Open Energy Info (EERE)

Hydrothermal Reservoirs Hydrothermal Reservoirs Jump to: navigation, search GEOTHERMAL ENERGYGeothermal Home Hydrothermal Reservoirs Dictionary.png Hydrothermal Reservoir: Hydrothermal Reservoirs are underground zones of porous rock containing hot water and steam, and can be naturally occurring or human-made. Other definitions:Wikipedia Reegle Natural, shallow hydrothermal reservoirs naturally occurring hot water reservoirs, typically found at depths of less than 5 km below the Earth's surface where there is heat, water and a permeable material (permeability in rock formations results from fractures, joints, pores, etc.). Often, hydrothermal reservoirs have an overlying layer that bounds the reservoir and also serves as a thermal insulator, allowing greater heat retention. If hydrothermal reservoirs

117

NETL: Oil & Natural Gas Technologies Reference Shelf - Presentation  

NLE Websites -- All DOE Office Websites (Extended Search)

Designing a Pilot-Scale Experiment for the Production of Natural Gas Hydrates and Sequestration of CO2 in Geologic Reservoirs Designing a Pilot-Scale Experiment for the Production...

118

Joule-Thomson Cooling Due to CO2 Injection into Natural Gas Reservoirs  

E-Print Network (OSTI)

feasibility of carbon sequestration with enhanced gasgas reservoirs for carbon sequestration and enhanced gaspromising target for Carbon Sequestration with Enhanced Gas

Oldenburg, Curtis M.

2006-01-01T23:59:59.000Z

119

Feasibility study on modeling and prediction of production behavior in naturally fractured shale reservoirs.  

E-Print Network (OSTI)

??The Objective of this study is to demonstrate the feasibility of predicting production characteristics in a Devonian Shale reservoir. This paper discusses the use of (more)

Huls, Boyd T.

2004-01-01T23:59:59.000Z

120

A triple-continuum pressure-transient model for a naturally fractured vuggy reservoir  

E-Print Network (OSTI)

reservoir. The fraction of oil reserves in a vuggy fracturedcontribute to oil and gas reserves and production [Kossackreserves estimation. Field Examples Pressure transient data from two oil-

2007-01-01T23:59:59.000Z

Note: This page contains sample records for the topic "natural geological reservoir" from the National Library of EnergyBeta (NLEBeta).
While these samples are representative of the content of NLEBeta,
they are not comprehensive nor are they the most current set.
We encourage you to perform a real-time search of NLEBeta
to obtain the most current and comprehensive results.


121

Naturally-Fractured Tight-Gas Reservoirs Phase II Final Report  

NLE Websites -- All DOE Office Websites (Extended Search)

Reservoirs, San Juan 12 Basin, New Mexico," SPE paper 11642, presented at the 1983 Symposium on Low Permeability, Denver, CO. Munoz, J.: "Delineation of Drainage Area and Flow...

122

3D geological modelling from boreholes, cross-sections and geological maps, application over former natural gas storages in coal mines  

Science Conference Proceedings (OSTI)

In a wide range of applications involving geological modelling, geological data available at low cost usually consist of documents such as cross-sections or geological maps and punctual data like borehole logs or outcrop descriptions. In order to build ... Keywords: 3D geological modelling, Data structuration, GIS, Geomodeler

Olivier Kaufmann; Thierry Martin

2008-03-01T23:59:59.000Z

123

Advanced reservoir characterization and evaluation of CO{sub 2} gravity drainage in the naturally fractured Spraberry reservoir. [Quarterly report], September 1, 1995--December 31, 1995  

Science Conference Proceedings (OSTI)

The objective of this research and the pilot project planned is to test the feasibility of CO{sub 2} for recovering oil from the naturally fractured Spraberry Trend Area in the Midland Basin. This notoriously marginal reservoir has confounded operators for 40 years with rapid depletion, low recovery during primary, disappointing waterflood results and low ultimate recovery. Yet, the tremendous areal coverage and large amount of remaining oil (up to 10 Bbbl) warrants further investigation to expend all possible process options before large numbers of Spraberry wellbores need to be plugged and abandoned. CO{sub 2} injection on a continuous, pattern wide basis has not been attempted in the Spraberry Trend. This is due to the obvious existence of a network of naturally occurring fractures. However, it has become clear in recent years that neglecting CO{sub 2} injection as an option in fractured reservoirs may overlook potential projects which may be viable. The 15 well pilot filed demonstration and supporting research will provide the necessary information to quantify the conditions where by CO{sub 2} flooding would be economic in the Spraberry Trend. Technical progress for this quarter is described for field and laboratory experiments.

Schechter, D. [New Mexico Petroleum Recovery Research Center, Socorro, NM (United States)

1995-12-31T23:59:59.000Z

124

Production of Natural Gas and Fluid Flow in Tight Sand Reservoirs  

Science Conference Proceedings (OSTI)

This document reports progress of this research effort in identifying relationships and defining dependencies between macroscopic reservoir parameters strongly affected by microscopic flow dynamics and production well performance in tight gas sand reservoirs. These dependencies are investigated by identifying the main transport mechanisms at the pore scale that should affect fluids flow at the reservoir scale. A critical review of commercial reservoir simulators, used to predict tight sand gas reservoir, revealed that many are poor when used to model fluid flow through tight reservoirs. Conventional simulators ignore altogether or model incorrectly certain phenomena such as, Knudsen diffusion, electro-kinetic effects, ordinary diffusion mechanisms and water vaporization. We studied the effect of Knudsen's number in Klinkenberg's equation and evaluated the effect of different flow regimes on Klinkenberg's parameter b. We developed a model capable of explaining the pressure dependence of this parameter that has been experimentally observed, but not explained in the conventional formalisms. We demonstrated the relevance of this, so far ignored effect, in tight sands reservoir modeling. A 2-D numerical simulator based on equations that capture the above mentioned phenomena was developed. Dynamic implications of new equations are comprehensively discussed in our work and their relative contribution to the flow rate is evaluated. We performed several simulation sensitivity studies that evidenced that, in general terms, our formalism should be implemented in order to get more reliable tight sands gas reservoirs' predictions.

Maria Cecilia Bravo

2006-06-30T23:59:59.000Z

125

Numerical simulations of the Macondo well blowout reveal strong control of oil flow by reservoir permeability and exsolution of gas  

E-Print Network (OSTI)

Reservoir Flow of Carbon Dioxide and Variable Salinityproduction, geologic carbon dioxide sequestration, nucleardeveloped for geologic carbon dioxide sequestration studies,

Oldenburg, C.M.

2013-01-01T23:59:59.000Z

126

Joule-Thomson Cooling Due to CO2 Injection into Natural Gas Reservoirs  

E-Print Network (OSTI)

cannot be produced because gas wells water out, a processcan be produced because there is no invading water to killwater flows into the reservoir from surrounding aquifers continuously while gas is produced.

Oldenburg, Curtis M.

2006-01-01T23:59:59.000Z

127

Production of Natural Gas and Fluid Flow in Tight Sand Reservoirs  

Science Conference Proceedings (OSTI)

This document reports progress of this research effort in identifying possible relationships and defining dependencies between macroscopic reservoir parameters strongly affected by microscopic flow dynamics and production well performance in tight gas sand reservoirs. Based on a critical review of the available literature, a better understanding of the main weaknesses of the current state of the art of modeling and simulation for tight sand reservoirs has been reached. Progress has been made in the development and implementation of a simple reservoir simulator that is still able to overcome some of the deficiencies detected. The simulator will be used to quantify the impact of microscopic phenomena in the macroscopic behavior of tight sand gas reservoirs. Phenomena such as, Knudsen diffusion, electro-kinetic effects, ordinary diffusion mechanisms and water vaporization are being considered as part of this study. To date, the adequate modeling of gas slippage in porous media has been determined to be of great relevance in order to explain unexpected fluid flow behavior in tight sand reservoirs.

Maria Cecilia Bravo; Mariano Gurfinkel

2005-06-30T23:59:59.000Z

128

Lessons Learned from Natural and Industrial Analogues for Storage of Carbon Dioxide in Deep Geological Formations  

E-Print Network (OSTI)

P.L.Determeyer, Natural gas storage: Historical developmentNatural Resources Canada, Natural Gas Storage: A CanadianU.S. underground natural gas storage working-gas capacity

Benson, Sally M.; Hepple, Robert; Apps, John; Tsang, Chin-Fu; Lippmann, Marcelo

2002-01-01T23:59:59.000Z

129

Joule-Thomson Cooling Due to CO2 Injection into Natural Gas Reservoirs  

E-Print Network (OSTI)

as cushion gas for natural gas storage, Energy & Fuels, 17(super-cushion gas for natural gas storage (Oldenburg, 2003).

Oldenburg, Curtis M.

2006-01-01T23:59:59.000Z

130

Relevance of underground natural gas storage to geologic sequestration of carbon dioxide  

E-Print Network (OSTI)

Underground Storage of Natural Gas in the United States andEnergy Information Agency (2002). U.S. Natural Gas Storage.www.eia.doe.gov/oil_gas/natural_gas/info_glance/storage.html

Lippmann, Marcelo J.; Benson, Sally M.

2002-01-01T23:59:59.000Z

131

Lessons Learned from Natural and Industrial Analogues for Storage of Carbon Dioxide in Deep Geological Formations  

E-Print Network (OSTI)

people) US Annual Natural Gas Production/Consumption - 1998people) US Annual Natural Gas Production/Consumption - 1998Annual Natural Gas Production/Consumption, 1998, U.S. DOE,

Benson, Sally M.; Hepple, Robert; Apps, John; Tsang, Chin-Fu; Lippmann, Marcelo

2002-01-01T23:59:59.000Z

132

Lessons Learned from Natural and Industrial Analogues for Storage of Carbon Dioxide in Deep Geological Formations  

E-Print Network (OSTI)

P.L.Determeyer, Natural gas storage: Historical development2000. Total U.S. Natural Gas Storage Capacity 1999, U.S.EIA) web page, U.S. natural gas storage, 2001. http://

Benson, Sally M.; Hepple, Robert; Apps, John; Tsang, Chin-Fu; Lippmann, Marcelo

2002-01-01T23:59:59.000Z

133

Exploration, Drilling and Development Operations in the Bottle Rock Area of the Geysers Steam Field, With New Geologic Insights and Models Defining Reservoir Parameters  

Science Conference Proceedings (OSTI)

MCR Geothermal Corporation pioneered successful exploratiory drilling the Bottle Rock area of the Geysers Steam Field in 1976. The wellfield is characterized by a deep reservoir with varied flowrates, temperatures, pressures, and stem chemistries being quite acceptable. More detailed reservoir engineering tests will follow as production commences.

Hebein, Jeffrey J.

1983-12-15T23:59:59.000Z

134

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

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}]).

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

2004-05-01T23:59:59.000Z

135

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

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.

Schechter, D.S.

1997-12-01T23:59:59.000Z

136

Lessons Learned from Natural and Industrial Analogues for Storage of Carbon Dioxide in Deep Geological Formations  

E-Print Network (OSTI)

natural gases in the Permian Basin, West Texas: IdentifyingUT Val-Verde Basin, Permian Basin Cooper- Eromanga Basin,

Benson, Sally M.; Hepple, Robert; Apps, John; Tsang, Chin-Fu; Lippmann, Marcelo

2002-01-01T23:59:59.000Z

137

Lessons Learned from Natural and Industrial Analogues for Storage of Carbon Dioxide in Deep Geological Formations  

E-Print Network (OSTI)

From One 500 MW Natural Gas Power Plant Weyburn EOR ProjectFrom One 500 MW Natural Gas Power Plant Weyburn EOR ProjectPower Plant Emissions Total Global Annual Human Expired CO 2 (6000 x 10 people) US Annual Natural Gas

Benson, Sally M.; Hepple, Robert; Apps, John; Tsang, Chin-Fu; Lippmann, Marcelo

2002-01-01T23:59:59.000Z

138

Preliminary formation analysis for compressed air energy storage in depleted natural gas reservoirs : a study for the DOE Energy Storage Systems Program.  

Science Conference Proceedings (OSTI)

The purpose of this study is to develop an engineering and operational understanding of CAES performance for a depleted natural gas reservoir by evaluation of relative permeability effects of air, water and natural gas in depleted natural gas reservoirs as a reservoir is initially depleted, an air bubble is created, and as air is initially cycled. The composition of produced gases will be evaluated as the three phase flow of methane, nitrogen and brine are modeled. The effects of a methane gas phase on the relative permeability of air in a formation are investigated and the composition of the produced fluid, which consists primarily of the amount of natural gas in the produced air are determined. Simulations of compressed air energy storage (CAES) in depleted natural gas reservoirs were carried out to assess the effect of formation permeability on the design of a simple CAES system. The injection of N2 (as a proxy to air), and the extraction of the resulting gas mixture in a depleted natural gas reservoir were modeled using the TOUGH2 reservoir simulator with the EOS7c equation of state. The optimal borehole spacing was determined as a function of the formation scale intrinsic permeability. Natural gas reservoir results are similar to those for an aquifer. Borehole spacing is dependent upon the intrinsic permeability of the formation. Higher permeability allows increased injection and extraction rates which is equivalent to more power per borehole for a given screen length. The number of boreholes per 100 MW for a given intrinsic permeability in a depleted natural gas reservoir is essentially identical to that determined for a simple aquifer of identical properties. During bubble formation methane is displaced and a sharp N2methane boundary is formed with an almost pure N2 gas phase in the bubble near the borehole. During cycling mixing of methane and air occurs along the boundary as the air bubble boundary moves. The extracted gas mixture changes as a function of time and proximity of the bubble boundary to the well. For all simulations reported here, with a formation radius above 50 m the maximum methane composition in the produced gas phase was less than 0.5%. This report provides an initial investigation of CAES in a depleted natural gas reservoir, and the results will provide useful guidance in CAES system investigation and design in the future.

Gardner, William Payton

2013-06-01T23:59:59.000Z

139

Preliminary formation analysis for compressed air energy storage in depleted natural gas reservoirs : a study for the DOE Energy Storage Systems Program.  

SciTech Connect

The purpose of this study is to develop an engineering and operational understanding of CAES performance for a depleted natural gas reservoir by evaluation of relative permeability effects of air, water and natural gas in depleted natural gas reservoirs as a reservoir is initially depleted, an air bubble is created, and as air is initially cycled. The composition of produced gases will be evaluated as the three phase flow of methane, nitrogen and brine are modeled. The effects of a methane gas phase on the relative permeability of air in a formation are investigated and the composition of the produced fluid, which consists primarily of the amount of natural gas in the produced air are determined. Simulations of compressed air energy storage (CAES) in depleted natural gas reservoirs were carried out to assess the effect of formation permeability on the design of a simple CAES system. The injection of N2 (as a proxy to air), and the extraction of the resulting gas mixture in a depleted natural gas reservoir were modeled using the TOUGH2 reservoir simulator with the EOS7c equation of state. The optimal borehole spacing was determined as a function of the formation scale intrinsic permeability. Natural gas reservoir results are similar to those for an aquifer. Borehole spacing is dependent upon the intrinsic permeability of the formation. Higher permeability allows increased injection and extraction rates which is equivalent to more power per borehole for a given screen length. The number of boreholes per 100 MW for a given intrinsic permeability in a depleted natural gas reservoir is essentially identical to that determined for a simple aquifer of identical properties. During bubble formation methane is displaced and a sharp N2methane boundary is formed with an almost pure N2 gas phase in the bubble near the borehole. During cycling mixing of methane and air occurs along the boundary as the air bubble boundary moves. The extracted gas mixture changes as a function of time and proximity of the bubble boundary to the well. For all simulations reported here, with a formation radius above 50 m the maximum methane composition in the produced gas phase was less than 0.5%. This report provides an initial investigation of CAES in a depleted natural gas reservoir, and the results will provide useful guidance in CAES system investigation and design in the future.

Gardner, William Payton

2013-06-01T23:59:59.000Z

140

Advanced reservoir characterization and evaluation of CO{sub 2} gravity drainage in the naturally fractured Spraberry reservoir. Quarterly technical report, April 1, 1996--June 30, 1996  

Science Conference Proceedings (OSTI)

Progress has been made in the area of laboratory analysis of Spraberry oil/brine/rock interactions during this quarter. Water imbibition experiments were conducted under ambient conditions, using cleaned Spraberry cores, synthetic Spraberry reservoir brine, and Spraberry oil. It has been concluded that the Spraberry reservoir cores are weakly water-wet. The average Amott wettability index to water is about 0.55. The average oil recovery due to spontaneous water imbibition is about 50% of original oil in place.

Schechter, D.

1996-11-01T23:59:59.000Z

Note: This page contains sample records for the topic "natural geological reservoir" from the National Library of EnergyBeta (NLEBeta).
While these samples are representative of the content of NLEBeta,
they are not comprehensive nor are they the most current set.
We encourage you to perform a real-time search of NLEBeta
to obtain the most current and comprehensive results.


141

Geologic control of natural marine hydrocarbon seep emissions, Coal Oil Point seep field, California  

E-Print Network (OSTI)

Formation, the primary source of petroleum hydrocarbons inPetroleum Geologists, Tulsa Clark JF, Washburn L, Hornafius JS, Luyendyk BP (2000) Natural marine hydrocarbon seep source

Leifer, Ira; Kamerling, Marc J.; Luyendyk, Bruce P.; Wilson, Douglas S.

2010-01-01T23:59:59.000Z

142

INVESTIGATION OF EFFICIENCY IMPROVEMENTS DURING CO2 INJECTION IN HYDRAULICALLY AND NATURALLY FRACTURED RESERVOIRS  

Science Conference Proceedings (OSTI)

The objective of this project is to perform unique laboratory experiments with artificial fractured cores (AFCs) and X-ray CT to examine the physical mechanisms of bypassing in HFR and NFR that eventually result in more efficient CO{sub 2} flooding in heterogeneous or fracture-dominated reservoirs. To achieve this objective, we divided the report into two chapters. The first chapter was to image and perform experimental investigation of transfer mechanisms during CO{sub 2} flooding in NFR and HFR using X-ray CT scanner. In this chapter, we emphasized our work on understanding the connection between fracture properties and fundamentals of transfer mechanism from matrix to fractures and fluid flow through fracture systems. We started our work by investigating the effect of different overburden pressures and stress-state conditions on rock properties and fluid flow. Since the fracture aperture is one of important parameter that governs the fluid flow through the fracture systems, the average fracture aperture from the fluid flow experiments and fracture aperture distribution derived from X-ray CT scan were estimated for our modeling purposes. The fracture properties and fluid flow have significant changes in response to different overburden pressures and stress-state conditions. The fracture aperture distribution follows lognormal distribution even at elevated stress conditions. Later, we also investigated the fluid transfers between matrix and fracture that control imbibition process. We evaluated dimensionless time for validating the scheme of upscaling laboratory experiments to field dimensions. In CO{sub 2} injection experiments, the use of X-ray CT has allowed us to understand the mechanisms of CO{sub 2} flooding process in fractured system and to take important steps in reducing oil bypassed. When CO{sub 2} flooding experiments were performed on a short core with a fracture at the center of the core, the gravity plays an important role in the recovery of oil even in a short matrix block. This results are contrary with the previous believes that gravity drainage has always been associated with tall matrix blocks. In order to reduce oil bypassed, we injected water that has been viscosified with a polymer into the fracture to divert CO{sub 2} flow into matrix and delay CO{sub 2} breakthrough. Although the breakthrough time reduced considerably, water ''leak off'' into the matrix was very high. A cross-linked gel was used in the fracture to avoid this problem. The gel was found to overcome ''leak off'' problems and effectively divert CO{sub 2} flow into the matrix. As part of our technology transfer activity, we investigated the natural fracture aperture distribution of Tensleep formation cores. We found that the measured apertures distributions follow log normal distribution as expected. The second chapter deals with analysis and modeling the laboratory experiments and fluid flow through fractured networks. We derived a new equation to determine the average fracture aperture and the amount of each flow through fracture and matrix system. The results of this study were used as the observed data and for validating the simulation model. The idea behind this study is to validate the use of a set of smooth parallel plates that is common in modeling fracture system. The results suggest that fracture apertures need to be distributed to accurately model the experimental results. In order to study the imbibition process in details, we developed imbibition simulator. We validated our model with X-ray CT experimental data from different imbibition experiments. We found that the proper simulation model requires matching both weight gain and CT water saturation simultaneously as oppose to common practices in matching imbibition process with weight gain only because of lack information from CT scan. The work was continued by developing dual porosity simulation using empirical transfer function (ETF) derived from imbibition experiments. This allows reduction of uncertainty parameter in modeling transfer of fluids from matrix to the fra

David S. Schechter

2005-09-28T23:59:59.000Z

143

Comparison of resource assessment methods and geologic controls--deep natural gas plays and zones, United States and Russia  

Science Conference Proceedings (OSTI)

Deep (greater than 4.5 km--15,000 ft) conventional natural gas resources will play an important role in the future energy needs of the United States and Russia. Deep sedimentary basins are widespread in these countries and have formed in a variety of depositional and tectonic settings. Significant volumes of undiscovered deep natural gas are in the Gulf Coast, Anadarko, Permian, and Rocky Mountain basins of the U.S., and in the Timan-Pechora, West Siberia, East Siberia, and North and South Caspian basins of the former Soviet Union. Deep natural gas resources are regularly assessed by the All-Russia Petroleum Research Exploration Institute (VNIGRI) and the U.S. Geological Survey (USGS) as part of their normal research activities. Both VNIGRI and the USGS employ similar assessment methods involving play (or zone) analysis using geological data and based on an analysis of confirmed and hypothetical plays using field-size distributions, discovery-process models, and statistical estimation procedures that yield probabilistic estimates of undiscovered accumulations. Resource estimates for the deep structural and statigraphic plays of the Anadarko basin and deep Paleozoic zones in the Timan-Pechora basin are compared and contrasted using both methods. Differences in results of assessments between VNIGRI and USGS arise due to (1) the way in which plays/zones are defined, (2) different geochemical models for hydrocarbon generation as applied to hypothetical plays, (3) variations in the ways in which statistical estimation procedures are applied to plays and regions, and (4) differences in economic and technologic assumptions, reserve growth calculations, and accumulation size limits and ranges.

Dyman, T.S. (Geological Survey, Denver, CO (United States)); Belonin, M.D. (All-Russia Petroleum Research Exploration Inst., St. Petersburg (Russian Federation)) (and others)

1996-01-01T23:59:59.000Z

144

Lessons Learned from Natural and Industrial Analogues for Storage of Carbon Dioxide in Deep Geological Formations  

E-Print Network (OSTI)

Histories Summary Conclusions and Remarks i UNDERGROUND NATURAL GASnatural gases in the Permian Basin, West Texas: Identifying the regional source and filling history,Natural Gas Storage Summary Conclusions and Remarks NUCLEAR WASTE DISPOSAL: LESSONS LEARNED FOR CO 2 SEQUESTRATION Introduction History

Benson, Sally M.; Hepple, Robert; Apps, John; Tsang, Chin-Fu; Lippmann, Marcelo

2002-01-01T23:59:59.000Z

145

Comparison of pressure ransient response in intensely and sparsely fractured reservoirs  

DOE Green Energy (OSTI)

A comprehensive analytical model is presented to study the pressure transient behavior of a naturally fractured reservoir with a continuous matrix block size distribution. Geologically realistic probability density functions of matrix block size are used to represent reservoirs of varying fracture intensity and uniformity. Transient interporosity flow is assumed and interporosity skin is incorporated. Drawdown and interference pressure transient tests are investigated. The results show distinctions in the pressure response from intensely and sparsely fractured reservoirs in the absence of interporosity skin. Also, uniformly and nonuniformly fractured reservoirs exhibit distinct responses, irrespective of the degree of fracture intensity. The pressure response in a nonuniformly fractured reservoir with large block size variability, approaches a nonfractured (homogeneous) reservoir response. Type curves are developed to estimate matrix block size variability and the degree of fracture intensity from drawdown and interference well tests.

Johns, R.T.

1989-01-01T23:59:59.000Z

146

Comparison of pressure transient response in intensely and sparsely fractured reservoirs  

DOE Green Energy (OSTI)

A comprehensive analytical model is presented to study the pressure transient behavior of a naturally fractured reservoir with a continuous matrix block size distribution. Geologically realistic probability density functions of matrix block size are used to represent reservoirs of varying fracture intensity and uniformity. Transient interporosity flow is assumed and interporosity skin is incorporated. Drawdown and interference pressure transient tests are investigated. The results show distinctions in the pressure response from intensely and sparsely fractured reservoirs in the absence of interporosity skin. Also, uniformly and nonuniformly fractured reservoirs exhibit distinct responses, irrespective of the degree of fracture intensity. The pressure response in a nonuniformly fractured reservoir with large block size variability, approaches a nonfractured (homogeneous) reservoir response. Type curves are developed to estimate matrix block size variability and the degree of fracture intensity from drawdown and interference well tests.

Johns, R.T.

1989-04-01T23:59:59.000Z

147

Nature's objects : geology, aesthetics, and the understanding of materiality in eighteenth-century Britain and France  

E-Print Network (OSTI)

Explorations of aesthetic design and scientific experimentation have traditionally relied upon the natural world as a source of inspiration. Notably absent from previous studies of the eighteenth century is the dynamic ...

Ferng, Jennifer Hsiao-Mei

2012-01-01T23:59:59.000Z

148

Lessons Learned from Natural and Industrial Analogues for Storage of Carbon Dioxide in Deep Geological Formations  

E-Print Network (OSTI)

MMTC Total Global Crude Oil Reserves 1998, U.S. DOE 2000,Total Global Crude Oil Reserves - 1999 Total Global Natural1998 Total US Crude Oil Reserves - 1998 Largest Single US

Benson, Sally M.; Hepple, Robert; Apps, John; Tsang, Chin-Fu; Lippmann, Marcelo

2002-01-01T23:59:59.000Z

149

Geologic setting and natural gas potential of Niobrara formation, Williston Basin  

SciTech Connect

Chalk units in the Niobrara Formation (Upper Cretaceous) have potential for generation and accumulation of shallow, biogenic gas in the central and eastern Williston basin. Similar to area of Niobrara gas production in the eastern Denver basin, Niobrara chalks in South and North Dakota were deposited on carbonate ramps sloping westward off the stable eastern platform of the Western Interior seaway. Within the Williston basin, the Niobrara of the western Dakotas, eastern North Dakota, and central South Dakota has different stratigraphic relationships. These three areas can be further subdivided and ranked into six areas that have different exploration potential. The south margin of the Williston basin in central South Dakota is the most attractive exploration area. Niobrara chalk reservoirs, source rocks, and structural traps in the southern Williston basin are similar to those in the eastern Denver basin. Chalk porosities are probably adequate for gas production, although porosity is controlled by burial depth. Organic carbon content of the chalk is high and shows of biogenic gas are reported. Large, low-relief structural features, which could serve as traps, are present.

Shurr, G.W.; Rice, D.D.

1985-05-01T23:59:59.000Z

150

Naturally fractured tight gas: Gas reservoir detection optimization. Quarterly report, January 1--March 31, 1997  

SciTech Connect

Economically viable natural gas production from the low permeability Mesaverde Formation in the Piceance Basin, Colorado requires the presence of an intense set of open natural fractures. Establishing the regional presence and specific location of such natural fractures is the highest priority exploration goal in the Piceance and other western US tight, gas-centered basins. Recently, Advanced Resources International, Inc. (ARI) completed a field program at Rulison Field, Piceance Basin, to test and demonstrate the use of advanced seismic methods to locate and characterize natural fractures. This project began with a comprehensive review of the tectonic history, state of stress and fracture genesis of the basin. A high resolution aeromagnetic survey, interpreted satellite and SLAR imagery, and 400 line miles of 2-D seismic provided the foundation for the structural interpretation. The central feature of the program was the 4.5 square mile multi-azimuth 3-D seismic P-wave survey to locate natural fracture anomalies. The interpreted seismic attributes are being tested against a control data set of 27 wells. Additional wells are currently being drilled at Rulison, on close 40 acre spacings, to establish the productivity from the seismically observed fracture anomalies. A similar regional prospecting and seismic program is being considered for another part of the basin. The preliminary results indicate that detailed mapping of fault geometries and use of azimuthally defined seismic attributes exhibit close correlation with high productivity gas wells. The performance of the ten new wells, being drilled in the seismic grid in late 1996 and early 1997, will help demonstrate the reliability of this natural fracture detection and mapping technology.

NONE

1997-12-31T23:59:59.000Z

151

Consolidation of geologic studies of geopressured-geothermal resources in Texas: Barrier-bar tidal-channel reservoir facies architecture, Jackson Group, Prado field, South Texas; Final report  

DOE Green Energy (OSTI)

Sandstone reservoirs in the Jackson barrier/strandplain play are characterized by low recovery efficiencies and thus contain a large hydrocarbon resource target potentially amenable to advanced recovery techniques. Prado field, Jim Hogg County, South Texas, has produced over 23 million bbl of oil and over 32 million mcf gas from combination structural-stratigraphic traps in the Eocene lower Jackson Group. Hydrocarbon entrapment at Prado field is a result of anticlinal nosing by differential compaction and updip pinch-out of barrier bar sandstone. Relative base-level lowering resulted in forced regression that established lower Jackson shoreline sandstones in a relatively distal location in central Jim Hogg County. Reservoir sand bodies at Prado field comprise complex assemblages of barrier-bar, tidal-inlet fill, back-barrier bar, and shoreface environments. Subsequent progradation built the barrier-bar system seaward 1 to 2 mi. Within the barrier-bar system, favorable targets for hydrocarbon reexploration are concentrated in tidal-inlet facies because they possess the greatest degree of depositional heterogeneity. The purpose of this report is (1) to describe and analyze the sand-body architecture, depositional facies variations, and structure of Prado field, (2) to determine controls on distribution of hydrocarbons pertinent to reexploration for bypassed hydrocarbons, (3) to describe reservoir models at Prado field, and (4) to develop new data affecting the suitability of Jackson oil fields as possible candidates for thermally enhanced recovery of medium to heavy oil.

Seni, S.J.; Choh, S.J.

1994-01-01T23:59:59.000Z

152

Intelligent seismic inversion workflow for high-resolution reservoir characterization  

Science Conference Proceedings (OSTI)

Developing a geological model is the first and a very important step during the reservoir simulation and modeling process. The geological model usually represents our best interpretation of the reservoir characteristics that extends beyond the well where ... Keywords: Buffalo Valley Field, Neural networks, Reservoir characterization, Seismic inversion

E. Artun; S. Mohaghegh

2011-02-01T23:59:59.000Z

153

Advanced Reservoir Characterization and Evaluation of CO{sub 2} Gravity Drainage in the Naturally Fractured Spraberry Trend Area, Class III  

Science Conference Proceedings (OSTI)

The goal of this project was to assess the economic feasibility of CO{sub 2} 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 CO{sub 2} gravity drainage in Spraberry whole cores. The four areas have been completed and reported in the previous annual reports. This report provides the results of the final year of the project including two SPE papers (SPE 71605 and SPE 71635) presented in the 2001 SPE Annual Meeting in New Orleans, two simulation works, analysis of logging observation wells (LOW) and progress of CO{sub 2} injection.

Knight, Bill; Schechter, David S.

2001-11-19T23:59:59.000Z

154

Geotechnical studies of geothermal reservoirs  

DOE Green Energy (OSTI)

It is proposed to delineate the important factors in the geothermal environment that will affect drilling. The geologic environment of the particular areas of interest are described, including rock types, geologic structure, and other important parameters that help describe the reservoir and overlying cap rock. The geologic environment and reservoir characteristics of several geothermal areas were studied, and drill bits were obtained from most of the areas. The geothermal areas studied are: (1) Geysers, California, (2) Imperial Valley, California, (3) Roosevelt Hot Springs, Utah, (4) Bacca Ranch, Valle Grande, New Mexico, (5) Jemez Caldera, New Mexico, (6) Raft River, Idaho, and (7) Marysville, Montona. (MHR)

Pratt, H.R.; Simonson, E.R.

1976-01-01T23:59:59.000Z

155

The Rosetta Resources CO2 Storage Project - A WESTCARB GeologicPilot Test  

SciTech Connect

WESTCARB, one of seven U.S. Department of Energypartnerships, identified (during its Phase I study) over 600 gigatonnesof CO2 storage capacity in geologic formations located in the Westernregion. The Western region includes the WESTCARB partnership states ofAlaska, Arizona, California, Nevada, Oregon and Washington and theCanadian province of British Columbia. The WESTCARB Phase II study iscurrently under way, featuring three geologic and two terrestrial CO2pilot projects designed to test promising sequestration technologies atsites broadly representative of the region's largest potential carbonsinks. This paper focuses on two of the geologic pilot studies plannedfor Phase II -referred to-collectively as the Rosetta-Calpine CO2 StorageProject. The first pilot test will demonstrate injection of CO2 into asaline formation beneath a depleted gas reservoir. The second test willgather data for assessing CO2 enhanced gas recovery (EGR) as well asstorage in a depleted gas reservoir. The benefit of enhanced oil recovery(EOR) using injected CO2 to drive or sweep oil from the reservoir towarda production well is well known. EaR involves a similar CO2 injectionprocess, but has received far less attention. Depleted natural gasreservoirs still contain methane; therefore, CO2 injection may enhancemethane production by reservoir repressurization or pressure maintenance.CO2 injection into a saline formation, followed by injection into adepleted natural gas reservoir, is currently scheduled to start inOctober 2006.

Trautz, Robert; Benson, Sally; Myer, Larry; Oldenburg, Curtis; Seeman, Ed; Hadsell, Eric; Funderburk, Ben

2006-01-30T23:59:59.000Z

156

Radionuclide Migration at the Rio Blanco Site, A Nuclear-stimulated Low-permeability Natural Gas Reservoir  

SciTech Connect

The U.S. Department of Energy and its predecessor agencies conducted a program in the 1960s and 1970s that evaluated technology for the nuclear stimulation of low-permeability gas reservoirs. The third and final project in the program, Project Rio Blanco, was conducted in Rio Blanco County, in northwestern Colorado. In this experiment, three 33-kiloton nuclear explosives were simultaneously detonated in a single emplacement well in the Mesaverde Group and Fort Union Formation, at depths of 1,780, 1,899, and 2,039 m below land surface on May 17, 1973. The objective of this work is to estimate lateral distances that tritium released from the detonations may have traveled in the subsurface and evaluate the possible effect of postulated natural-gas development on radionuclide migration. Other radionuclides were considered in the analysis, but the majority occur in relatively immobile forms (such as nuclear melt glass). Of the radionuclides present in the gas phase, tritium dominates in terms of quantity of radioactivity in the long term and contribution to possible whole body exposure. One simulation is performed for {sup 85}Kr, the second most abundant gaseous radionuclide produced after tritium.

Clay A. Cooper; Ming Ye; Jenny Chapman; Craig Shirley

2005-10-01T23:59:59.000Z

157

Evolution of the Cerro Prieto reservoirs under exploitation  

DOE Green Energy (OSTI)

The Cerro Prieto Geothermal field of Baja California (Mexico) has been under commercial production to generate electricity since 1973. Over the years, the large amount of Geothermal fluids extracted (at present about 12,000 tons per hour) to supply steam to the power plants has resulted in a reduction of pressures, changes in reservoir processes, and increased flow of cooler groundwater into the geothermal system. The groundwater recharging the reservoir moves horizontally through permeable layers, as well as vertically through permeable fault zones. In addition, the supply of deep hot waters has continued unabated, and perhaps has increased as reservoir pressure decreased. Since 1989, this natural fluid recharge has been supplemented by injection which presently amounts to about 20% of the fluid produced. Changes in the chemical and physical characteristics of the reservoir fluids due to the drop in pressures and the inflow of cooler groundwaters and injectate have been detected on the basis of wellhead data. These changes point to reservoir processes like local boiling, phase segregation, steam condensation, mixing and dilution. Finally, the study identified areas where fluids are entering the reservoir, as well as indicated their source (i.e. natural Groundwater recharge versus injectate) and established the controlling geologic structures.

Truesdell, A.H.; Lippmann, M.J. [Lawrence Berkeley National Lab., CA (United States); Puente, H.G. [Comision Federal de Electricidad, Mexicali (Mexico)

1997-07-01T23:59:59.000Z

158

System-level modeling for geological storage of CO2  

E-Print Network (OSTI)

Gas Reservoirs for Carbon Sequestration and Enhanced Gasfrom geologic carbon sequestration sites, Vadose Zonethe feasibility of carbon sequestration with enhanced gas

Zhang, Yingqi; Oldenburg, Curtis M.; Finsterle, Stefan; Bodvarsson, Gudmundur S.

2006-01-01T23:59:59.000Z

159

Blackfoot Reservoir Geothermal Area | Open Energy Information  

Open Energy Info (EERE)

Blackfoot Reservoir Geothermal Area Blackfoot Reservoir Geothermal Area (Redirected from Blackfoot Reservoir Area) Jump to: navigation, search GEOTHERMAL ENERGYGeothermal Home Geothermal Resource Area: Blackfoot Reservoir Geothermal Area Contents 1 Area Overview 2 History and Infrastructure 3 Regulatory and Environmental Issues 4 Exploration History 5 Well Field Description 6 Geology of the Area 7 Geofluid Geochemistry 8 NEPA-Related Analyses (0) 9 Exploration Activities (3) 10 References Area Overview Geothermal Area Profile Location: Idaho Exploration Region: Northern Basin and Range Geothermal Region GEA Development Phase: 2008 USGS Resource Estimate Mean Reservoir Temp: Estimated Reservoir Volume: Mean Capacity: Click "Edit With Form" above to add content History and Infrastructure Operating Power Plants: 0

160

Integrated reservoir characterization for the Mazari oil field, Pakistan  

E-Print Network (OSTI)

This thesis describes a field study performed on the Mazari oil field located in Sind province, Pakistan. We used an integrated reservoir characterization technique to incorporate the geological, petrophysical, and reservoir performance data to interpret historical reservoir performance, to assess and refine reservoir management activities, and to make plans for future reservoir developments. We used a modified approach to characterize within the mappable geological facies. Our approach is based on the Kozeny-Carmen equation and uses the concept of mean hydraulic radius. As part of our objective to characterize the reservoir, we tabulated reservoir characteristics for each hydraulic flow unit, and we presented estimates of in-place reserves. We evaluated reservoir performance potential using the production history, well tests and cased-hole well log surveys. Suggestions for reservoir management activities in conjunction with the evaluation of the reservoir performance are discussed in detail. Finally, we give recommendations for activities in reservoir development particularly infill drilling considerations and secondary recovery efforts.

Ashraf, Ejaz

1994-01-01T23:59:59.000Z

Note: This page contains sample records for the topic "natural geological reservoir" from the National Library of EnergyBeta (NLEBeta).
While these samples are representative of the content of NLEBeta,
they are not comprehensive nor are they the most current set.
We encourage you to perform a real-time search of NLEBeta
to obtain the most current and comprehensive results.


161

Geotechnical studies of geothermal reservoirs | Open Energy Information  

Open Energy Info (EERE)

Geotechnical studies of geothermal reservoirs Geotechnical studies of geothermal reservoirs Jump to: navigation, search GEOTHERMAL ENERGYGeothermal Home Report: Geotechnical studies of geothermal reservoirs Details Activities (7) Areas (7) Regions (0) Abstract: It is proposed to delineate the important factors in the geothermal environment that will affect drilling. The geologic environment of the particular areas of interest are described, including rock types, geologic structure, and other important parameters that help describe the reservoir and overlying cap rock. The geologic environment and reservoir characteristics of several geothermal areas were studied, and drill bits were obtained from most of the areas. The geothermal areas studied are: (1) Geysers, California, (2) Imperial Valley, California, (3) Roosevelt Hot

162

GEOLOGY, January 2007 85Geology, January 2007; v. 35; no. 1; p. 8588; doi: 10.1130/G23101A.1; 5 figures; Data Repository item 2007026. 2007 Geological Society of America. For permission to copy, contact Copyright Permissions, GSA, or editing@geosociety.o  

E-Print Network (OSTI)

, Hydrocarbon Source Rocks, Tight gas sand reservoirs Heaman, Larry Isotope geology, geochronology, geochemistry of petroleum; conventional and unconventional source rocks; principles of migration; reservoir rocks; traps and environmental concerns Gleeson, Sarah Economic geology, hydrothermal geochemistry, water/rock interactions Haas

Svensen, Henrik

163

A geologic assessment of natural gas from tight gas sandstones in the San Juan Basin. Final report, June 1989--June 1991  

Science Conference Proceedings (OSTI)

The authors conducted a detailed geologic appraisal, estimated gas in place and recoverable volumes, and evaluated the impact of technology improvements on potential Cretaceous (Pictured Cliffs, Chacra, Cliff House, Point Lookout and Dakota intervals) tight gas reserves of the San Juan Basin. This report summarizes the results of a disaggregated appraisal of the undeveloped San Juan tight gas resource in the context of current and near-term technology, project economics and market potential. A geologic data base was constructed based on location reservoir properties, and typical well recoveries were modeled on a township-specific basis. Project costing and cash flow economics were analyzed to derive potential reserves for various technology specifications and wellhead prices. These data provide a foundation for operators and pipelines to more closely examine these tight formations for development in the near future. Gas in place for the undeveloped tight portion of the five intervals studied was estimated at 17.2 Tcf, with the Dakota Formation accounting for two thirds of this volume. Using current technology, potential ultimate recovery for all intervals is 7.2 Tcf. Potential reserve additions are 1.1 Tcf at $1.50/Mcf, 2.3 Tcf at $2.00/Mcf, and 5.9 Tcf at $5.00/Mcf. The availability of the Nonconventional Fuels Tax Credit for eligible wells drilled in 1991 and 1992 could improve project economics by an after tax equivalent of $0.66/Mcf at the wellhead. Over 300 geophysical logs were evaluated to construct depth, overburden and isopach maps and a location-specific resource database. The database was analyzed using TGAS-PC{reg_sign}, an integrated engineering and economics model for tight sands that has the capability to do rapid sensitivity analysis of geological, technology and economic assumptions.

Haas, M.R.; Lombardi, T.E.

1983-01-01T23:59:59.000Z

164

Reprint of "3D geological modelling from boreholes, cross-sections and geological maps, application over former natural gas storages in coal mines" [Comput. Geosci. 34 (2008) 278-290  

Science Conference Proceedings (OSTI)

In a wide range of applications involving geological modelling, geological data available at low cost usually consist of documents such as cross-sections or geological maps and punctual data like borehole logs or outcrop descriptions. In order to build ... Keywords: 3D geological modelling, Data structuration, GIS, Geomodeler

Olivier Kaufmann; Thierry Martin

2009-01-01T23:59:59.000Z

165

Fracture characterization of multilayered reservoirs  

Science Conference Proceedings (OSTI)

Fracture treatment optimization techniques have been developed using Long-Spaced-Digital-Sonic (LSDS) log, pumpin-flowback, mini-frac, and downhole treating pressure data. These analysis techniques have been successfully applied in massive hydraulic fracturing (MHF) of ''tight gas'' wells. Massive hydraulic fracture stimulations have been used to make many tight gas reservoirs commercially attractive. However, studies have shown that short highly conductive fractures are optimum for the successful stimulation of wells in moderate permeability reservoirs. As a result, the ability to design and place optimal fractures in these reservoirs is critical. This paper illustrates the application of fracture analysis techniques to a moderate permeability multi-layered reservoir. These techniques were used to identify large zonal variations in rock properties and pore pressure which result from the complex geology. The inclusion of geologic factors in fracture treatment design allowed the placement of short highly conductive fractures which were used to improve injectivity and vertical sweep, and therefore, ultimate recovery.

Britt, L.K.; Larsen, M.J.

1986-01-01T23:59:59.000Z

166

Characterization of oil and gas reservoir heterogeneity  

SciTech Connect

The ultimate oojective of this cooperative research project is to characterize Alaskan petroleum reservoirs in terms of their reserves, physical and chemical properties, geologic configuration in relation to lithofacies and structure, and development potential. The project has two tasks: Task 1 is a geological description of the reservoirs including petrophysical properties, i.e., porosity, permeability, permeability variation, formation depth, temperature, and net pay, facies changes and reservoir structures as drawn from cores, well logs, and other geological data. Task 2 is reservoir fluid characterization--determination of physical properties of reservoir fluids including density, viscosity, phase distributions and composition as well as petrogenesis--source rock identification; and the study of asphaltene precipitation for Alaskan crude oils. This report presents a summary of technical progress of the well log analysis of Kuparuk Field, Northslope, Alaska.

Sharma, G.D.

1992-01-01T23:59:59.000Z

167

Characterization of oil and gas reservoir heterogeneity  

SciTech Connect

The ultimate objective of this cooperative research project is to characterize Alaskan petroleum reservoirs in terms of their reserves, physical and chemical properties, geologic configuration in relation to lithofacies and structure, and development potential. The project has two tasks: Task 1 is a geological description of the reservoirs including petrophysical properties, i.e., porosity, permeability, permeability variation, formation depth, temperature, and net pay, facies changes and reservoir structures as drawn from cores, well logs, and other geological data. Task 2 is reservoir fluid characterization -- determination of physical properties of reservoir fluids including density, viscosity, phase distributions and composition as well as petrogenesis -- source rock identification; and the study of asphaltene precipitation for Alaskan crude oils.

Sharma, G.D.

1991-01-01T23:59:59.000Z

168

Characterization of oil and gas reservoir heterogeneity  

SciTech Connect

The ultimate objective of this cooperative research project is to characterize Alaskan petroleum reservoirs in terms of their reserves, physical and chemical properties, geologic configuration in relation to lithofacies and structure, and development potential. The project has two tasks: Task 1 is a geological description of the reservoirs including petrophysical properties, i.e., porosity, permeability, permeability variation, formation depth, temperature, and net pay, facies changes and reservoir structures as drawn from cores, well logs, and other geological data. Task 2 is reservoir fluid characterization-determination of physical properties of reservoir fluids including density, viscosity, phase distributions and composition as well as petrogenesis-source rock identification; and the study of asphaltene precipitation for Alaskan crude oils. Results are discussed.

Sharma, G.D.

1992-01-01T23:59:59.000Z

169

Assessing the health risks of natural CO2 seeps in Italy  

E-Print Network (OSTI)

Greenhouse Gas, Cheltenham, United Kingdom), Natural Ana- logues for the Geological Storage of CO2, IEA for assessing the health risks of CO2 leakage from on- shore storage reservoirs. Italian gas seeps have already Italian Gas Seeps. Natural CO2 degassing is most abundant in wes- tern Italy (18­20) (Fig. 1). Here

Haszeldine, Stuart

170

Pre-test geological and geochemical evaluation of the Caprock, St. Peter Sandstone and formation fluids, Yakley Field, Pike County, Illinois  

DOE Green Energy (OSTI)

The goal of these studies is to ensure long-term stable containment of air in the underground reservoirs used in conjunction with compressed air energy storage (CAES) plants. The specific objective is to develop stability criteria and engineering guidelines for designing CAES reservoirs in each of the three major reservoir types, including aquifers, salt cavities, and mined hard rock caverns. This document characterizes the geologic nature of porous media constituents native to the aquifer field test site near Pittsfield, Illinois. The geologic samples were subjected to geochemical evaluations to determine anticipated responses to cyclic air injection, heating and moisture - conditions typical of an operating CAES reservoir. This report documents the procedures used and results obtained from these analyses.

Not Available

1983-03-01T23:59:59.000Z

171

Geysers reservoir studies  

DOE Green Energy (OSTI)

LBL is conducting several research projects related to issues of interest to The Geysers operators, including those that deal with understanding the nature of vapor-dominated systems, measuring or inferring reservoir processes and parameters, and studying the effects of liquid injection. All of these topics are directly or indirectly relevant to the development of reservoir strategies aimed at stabilizing or increasing production rates of non-corrosive steam, low in non-condensable gases. Only reservoir engineering studies will be described here, since microearthquake and geochemical projects carried out by LBL or its contractors are discussed in accompanying papers. Three reservoir engineering studies will be described in some detail, that is: (a) Modeling studies of heat transfer and phase distribution in two-phase geothermal reservoirs; (b) Numerical modeling studies of Geysers injection experiments; and (c) Development of a dual-porosity model to calculate mass flow between rock matrix blocks and neighboring fractures.

Bodvarsson, G.S.; Lippmann, M.J.; Pruess, K.

1993-04-01T23:59:59.000Z

172

Blackfoot Reservoir Geothermal Area | Open Energy Information  

Open Energy Info (EERE)

Blackfoot Reservoir Geothermal Area Blackfoot Reservoir Geothermal Area Jump to: navigation, search GEOTHERMAL ENERGYGeothermal Home Geothermal Resource Area: Blackfoot Reservoir Geothermal Area Contents 1 Area Overview 2 History and Infrastructure 3 Regulatory and Environmental Issues 4 Exploration History 5 Well Field Description 6 Geology of the Area 7 Geofluid Geochemistry 8 NEPA-Related Analyses (0) 9 Exploration Activities (3) 10 References Area Overview Geothermal Area Profile Location: Idaho Exploration Region: Northern Basin and Range Geothermal Region GEA Development Phase: 2008 USGS Resource Estimate Mean Reservoir Temp: Estimated Reservoir Volume: Mean Capacity: Click "Edit With Form" above to add content History and Infrastructure Operating Power Plants: 0 No geothermal plants listed.

173

Application of Integrated Reservoir Management and Reservoir Characterization to Optimize Infill Drilling  

Science Conference Proceedings (OSTI)

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.

None

1998-01-01T23:59:59.000Z

174

Effect of matrix shrinkage on permeability of coalbed methane reservoirs .  

E-Print Network (OSTI)

??The dynamic nature of coalbed methane reservoir permeability makes the continuous modeling of the flow process difficult. Knowledge of conventional reservoir modeling is of little (more)

Tandon, Rohit, 1966-

1991-01-01T23:59:59.000Z

175

A virtual company concept for reservoir management  

SciTech Connect

This paper describes how reservoir management problems were pursued with a virtual company concept via the Internet and World Wide Web. The focus of the paper is on the implementation of virtual asset management teams that were assembled with small independent oil companies. The paper highlights the mechanics of how the virtual team transferred data and interpretations, evaluated geological models of complex reservoirs, and used results of simulation studies to analyze various reservoir management strategies.

Martin, F.D. [Dave Martin and Associates, Inc. (United States); Kendall, R.P.; Whitney, E.M. [Los Alamos National Lab., NM (United States)

1998-12-31T23:59:59.000Z

176

EOS7C Version 1.0: TOUGH2 Module for Carbon Dioxide or Nitrogen in Natural Gas (Methane) Reservoirs  

E-Print Network (OSTI)

as cushion gas for natural gas storage, Energy&Fuels ,2 as a cushion gas for natural gas storage can be found in

Oldenburg, Curtis M.; Moridis, George J.; Spycher, Nicholas; Pruess, Karsten

2004-01-01T23:59:59.000Z

177

Advanced reservoir characterization and evaluation of CO{sub 2} gravity drainage in the naturally fractured Spraberry Trend Area. First annual technical progress report, September 1, 1995--August 31, 1996  

SciTech Connect

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) 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.

Schechter, D.S.

1996-12-17T23:59:59.000Z

178

Application of Integrated Reservoir Management and Reservoir Characterization to Optimize Infill Drilling  

SciTech Connect

Initial drilling of wells on a uniform spacing, without regard to reservoir performance and characterization, must become a process of the past. Such efforts do not optimize reservoir development as they fail to account for the complex nature of reservoir heterogeneities present in many low permeability reservoirs, and carbonate reservoirs in particular. These reservoirs are typically characterized by: o Large, discontinuous pay intervals o Vertical and lateral changes in reservoir properties o Low reservoir energy o High residual oil saturation o Low recovery efficiency

P. K. Pande

1998-10-29T23:59:59.000Z

179

Seismic Determination of Reservoir Heterogeneity: Application to the Characterization of Heavy Oil Reservoirs  

Science Conference Proceedings (OSTI)

The objective of the project was to examine how seismic and geologic data could be used to improve characterization of small-scale heterogeneity and their parameterization in reservoir models. The study was performed at West Coalinga Field in California.

Imhof, Matthias G.; Castle, James W.

2003-03-12T23:59:59.000Z

180

Characterization of oil and gas reservoir heterogeneity  

SciTech Connect

The objective of the cooperative research program is to characterize Alaskan reservoirs in terms of their reserves, physical and chemical properties, geologic configuration and structure, and the development potential. The tasks completed during this period include: (1) geologic reservoir description of Endicott Field; (2) petrographic characterization of core samples taken from selected stratigraphic horizons of the West Sak and Ugnu (Brookian) wells; (3) development of a polydispersed thermodynamic model for predicting asphaltene equilibria and asphaltene precipitation from crude oil-solvent mixtures, and (4) preliminary geologic description of the Milne Point Unit.

Not Available

1991-01-01T23:59:59.000Z

Note: This page contains sample records for the topic "natural geological reservoir" from the National Library of EnergyBeta (NLEBeta).
While these samples are representative of the content of NLEBeta,
they are not comprehensive nor are they the most current set.
We encourage you to perform a real-time search of NLEBeta
to obtain the most current and comprehensive results.


181

Mathematical models of thermal and chemical transport in geologic media  

DOE Green Energy (OSTI)

Semi-analytical and numerical methods are used to investigate thermal and chemical transport processes in geologic media. The work is divided into two parts: (1) development of semi-analytical models for the analysis of uncoupled isothermal and nonisothermal fluid flow in naturally fractured media, and (2) development of a high resolution numerical code to address coupled nonisothermal chemical transport in geologic media. A semi-analytical model is developed for well test data analysis in naturally fractured reservoirs. A simple approximate analytical solution for pressure buildup and drawdown tests is developed. Methods based on the approximate solution are developed for the evaluation of important reservoir properties. Type curves for nonisothermal fluid flow in naturally fractured media are developed to design injection systems for maximum energy in hydrothermal systems. An accurate finite difference method for the solution of a convection-diffusion type equation is developed. The method is incorporated in a two-dimensional code to investigate free convection in a porous slab and kinetic silica-water reactions in geothermal systems. A multicomponent model considering the variations of pressure, temperature and silica concentration is developed to interpret the evolution of geothermal systems during exploitation.

Lai, C.-H.

1985-12-01T23:59:59.000Z

182

On leakage and seepage from geological carbon sequestration sites  

E-Print Network (OSTI)

gas fields and in natural gas storage operations. One largeof gas reservoir and natural gas storage analogs, along withoriginated from a natural gas storage facility eight miles

Oldenburg, C.M.; Unger, A.J.A.; Hepple, R.P.; Jordan, P.D.

2002-01-01T23:59:59.000Z

183

Certification Framework Based on Effective Trapping for Geologic Carbon Sequestration  

E-Print Network (OSTI)

Hillebrenner) field as a natural gas storage facility andgroundwater recharge, natural gas storage, solution mining,leg of the Fulshear natural gas storage reservoir southeast

Oldenburg, Curtis M.

2009-01-01T23:59:59.000Z

184

Installation of a Devonian Shale Reservoir Testing Facility and acquisition of reservoir property measurements  

SciTech Connect

In October, a contract was awarded for the Installation of a Devonian Shale Reservoir Testing Facility and Acquisition of Reservoir Property measurements from wells in the Michigan, Illinois, and Appalachian Basins. Geologic and engineering data collected through this project will provide a better understanding of the mechanisms and conditions controlling shale gas production. This report summarizes the results obtained from the various testing procedures used at each wellsite and the activities conducted at the Reservoir Testing Facility.

Locke, C.D.; Salamy, S.P.

1991-09-01T23:59:59.000Z

185

Installation of a Devonian Shale Reservoir Testing Facility and acquisition of reservoir property measurements. Final report  

SciTech Connect

In October, a contract was awarded for the Installation of a Devonian Shale Reservoir Testing Facility and Acquisition of Reservoir Property measurements from wells in the Michigan, Illinois, and Appalachian Basins. Geologic and engineering data collected through this project will provide a better understanding of the mechanisms and conditions controlling shale gas production. This report summarizes the results obtained from the various testing procedures used at each wellsite and the activities conducted at the Reservoir Testing Facility.

Locke, C.D.; Salamy, S.P.

1991-09-01T23:59:59.000Z

186

A Temperature-Profile Method for Estimating Flow Processes in Geologic Heat Pipes  

E-Print Network (OSTI)

change and capillaritythe heat pipe effect, Int. J. Heatgeothermal reservoirs as heat pipes in fractured porousProcesses in Geologic Heat Pipes Jens T. Birkholzer Ernest

Birkholzer, Jens T.

2004-01-01T23:59:59.000Z

187

Multi-Site Application of the Geomechanical Approach for Natural Fracture Exploration  

SciTech Connect

In order to predict the nature and distribution of natural fracturing, Advanced Resources Inc. (ARI) incorporated concepts of rock mechanics, geologic history, and local geology into a geomechanical approach for natural fracture prediction within mildly deformed, tight (low-permeability) gas reservoirs. Under the auspices of this project, ARI utilized and refined this approach in tight gas reservoir characterization and exploratory activities in three basins: the Piceance, Wind River and the Anadarko. The primary focus of this report is the knowledge gained on natural fractural prediction along with practical applications for enhancing gas recovery and commerciality. Of importance to tight formation gas production are two broad categories of natural fractures: (1) shear related natural fractures and (2) extensional (opening mode) natural fractures. While arising from different origins this natural fracture type differentiation based on morphology is sometimes inter related. Predicting fracture distribution successfully is largely a function of collecting and understanding the available relevant data in conjunction with a methodology appropriate to the fracture origin. Initially ARI envisioned the geomechanical approach to natural fracture prediction as the use of elastic rock mechanics methods to project the nature and distribution of natural fracturing within mildly deformed, tight (low permeability) gas reservoirs. Technical issues and inconsistencies during the project prompted re-evaluation of these initial assumptions. ARI's philosophy for the geomechanical tools was one of heuristic development through field site testing and iterative enhancements to make it a better tool. The technology and underlying concepts were refined considerably during the course of the project. As with any new tool, there was a substantial learning curve. Through a heuristic approach, addressing these discoveries with additional software and concepts resulted in a stronger set of geomechanical tools. Thus, the outcome of this project is a set of predictive tools with broad applicability across low permeability gas basins where natural fractures play an important role in reservoir permeability. Potential uses for these learnings and tools range from rank exploration to field-development portfolio management. Early incorporation of the permeability development concepts presented here can improve basin assessment and direct focus to the high potential areas within basins. Insight into production variability inherent in tight naturally fractured reservoirs leads to improved wellbore evaluation and reduces the incidence of premature exits from high potential plays. A significant conclusion of this project is that natural fractures, while often an important, overlooked aspect of reservoir geology, represent only one aspect of the overall reservoir fabric. A balanced perspective encompassing all aspects of reservoir geology will have the greatest impact on exploration and development in the low permeability gas setting.

R. L. Billingsley; V. Kuuskraa

2006-03-31T23:59:59.000Z

188

ASSESSING AND FORECASTING, BY PLAY, NATURAL GAS ULTIMATE RECOVERY GROWTH AND QUANTIFYING THE ROLE OF TECHNOLOGY ADVANCEMENTS IN THE TEXAS GULF COAST BASIN AND EAST TEXAS  

SciTech Connect

A detailed natural gas ultimate recovery growth (URG) analysis of the Texas Gulf Coast Basin and East Texas has been undertaken. The key to such analysis was determined to be the disaggregation of the resource base to the play level. A play is defined as a conceptual geologic unit having one or more reservoirs that can be genetically related on the basis of depositional origin of the reservoir, structural or trap style, source rocks and hydrocarbon generation, migration mechanism, seals for entrapment, and type of hydrocarbon produced. Plays are the geologically homogeneous subdivision of the universe of petroleum pools within a basin. Therefore, individual plays have unique geological features that can be used as a conceptual model that incorporates geologic processes and depositional environments to explain the distribution of petroleum. Play disaggregation revealed important URG trends for the major natural gas fields in the Texas Gulf Coast Basin and East Texas. Although significant growth and future potential were observed for the major fields, important URG trends were masked by total, aggregated analysis based on a broad geological province. When disaggregated by plays, significant growth and future potential were displayed for plays that were associated with relatively recently discovered fields, deeper reservoir depths, high structural complexities due to fault compartmentalization, reservoirs designated as tight gas/low-permeability, and high initial reservoir pressures. Continued technology applications and advancements are crucial in achieving URG potential in these plays.

William L. Fisher; Eugene M. Kim

2000-12-01T23:59:59.000Z

189

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

Science Conference Proceedings (OSTI)

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.

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

1999-04-28T23:59:59.000Z

190

CHARACTERIZATION OF CONDITIONS OF NATURAL GAS STORAGE RESERVOIRS AND DESIGN AND DEMONSTRATION OF REMEDIAL TECHNIQUES FOR DAMAGE MECHANISMS FOUND THEREIN  

SciTech Connect

The underground gas storage (UGS) industry uses over 400 reservoirs and 17,000 wells to store and withdrawal gas. As such, it is a significant contributor to gas supply in the United States. It has been demonstrated that many UGS wells show a loss of deliverability each year due to numerous damage mechanisms. Previous studies estimate that up to one hundred million dollars are spent each year to recover or replace a deliverability loss of approximately 3.2 Bscf/D per year in the storage industry. Clearly, there is a great potential for developing technology to prevent, mitigate, or eliminate the damage causing deliverability losses in UGS wells. Prior studies have also identified the presence of several potential damage mechanisms in storage wells, developed damage diagnostic procedures, and discussed, in general terms, the possible reactions that need to occur to create the damage. However, few studies address how to prevent or mitigate specific damage types, and/or how to eliminate the damage from occurring in the future. This study seeks to increase our understanding of two specific damage mechanisms, inorganic precipitates (specifically siderite), and non-darcy damage, and thus serves to expand prior efforts as well as complement ongoing gas storage projects. Specifically, this study has resulted in: (1) An effective lab protocol designed to assess the extent of damage due to inorganic precipitates; (2) An increased understanding of how inorganic precipitates (specifically siderite) develop; (3) Identification of potential sources of chemical components necessary for siderite formation; (4) A remediation technique that has successfully restored deliverability to storage wells damaged by the inorganic precipitate siderite (one well had nearly a tenfold increase in deliverability); (5) Identification of the types of treatments that have historically been successful at reducing the amount of non-darcy pressure drop in a well, and (6) Development of a tool that can be used by operators to guide treatment selection in wells with significant non-darcy damage component. In addition, the effectiveness of the remediation treatment designed to reduce damage caused by the inorganic precipitate siderite was measured, and the benefits of this work are extrapolated to the entire U.S. storage industry. Similarly the potential benefits realized from more effective identification and treatment of wells with significant nondarcy damage component are also presented, and these benefits are also extrapolated to the entire U.S. storage industry.

J.H. Frantz Jr; K.G. Brown; W.K. Sawyer; P.A. Zyglowicz; P.M. Halleck; J.P. Spivey

2004-12-01T23:59:59.000Z

191

Geology of Nevada: The  

E-Print Network (OSTI)

Geology plays a central role in Nevadas human history, economy, and future. Cordilleran tectonics have created the Basin and Range landscape and interior drainage of the Great Basin, provided a rain shadow to make Nevada the nations driest state, and generated frequent earthquakes along normal and strike-slip faults. Geology is key to reducing risks from Nevadas natural and anthropogenic hazards (earthquakes, flash floods, drought, land subsidence, erosion after wildland fires, landslides, swelling and collapsing soils, radon, arsenic, and others). Nevadas geologic fortunes make it the leading state in the production of gold, silver, barite, lithium, and mercury and a major producer of geothermal power and gypsum. The metals are primarily related to igneous activity, with major pulses of magma during the Jurassic, Cretaceous, and Tertiary. Barite is mined from Paleozoic

Jonathan G. Price

2002-01-01T23:59:59.000Z

192

Feasibility of Optimizing Recovery and Reserves from a Mature and Geological Complex Multiple Turbidite Offshore Calif. Reservoir through the Drilling and Completion of a Trilateral Horizontal Well, Class III  

SciTech Connect

The intent of this project was to increase production and extend the economic life of this mature field through the application of advanced reservoir characterization and drilling technology, demonstrating the efficacy of these technologies to other small operators of aging fields. Two study periods were proposed; the first to include data assimilation and reservoir characterization and the second to drill the demonstration well. The initial study period showed that a single tri-lateral well would not be economically efficient in redevelopment of Carpinteria's multiple deep water turbidite sand reservoirs, and the study was amended to include the drilling of a series of horizontal redrills from existing surplus well bores on Pacific Operators' Platform Hogan.

Pacific Operators Offshore, Inc.

2001-04-04T23:59:59.000Z

193

Storage capacity in hot dry rock reservoirs  

DOE Patents (OSTI)

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.

Brown, D.W.

1997-11-11T23:59:59.000Z

194

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

Science Conference Proceedings (OSTI)

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.

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

2006-11-01T23:59:59.000Z

195

Preliminary Geologic Characterization of West Coast States for Geologic Sequestration  

SciTech Connect

Characterization of geological sinks for sequestration of CO{sub 2} in California, Nevada, Oregon, and Washington was carried out as part of Phase I of the West Coast Regional Carbon Sequestration Partnership (WESTCARB) project. Results show that there are geologic storage opportunities in the region within each of the following major technology areas: saline formations, oil and gas reservoirs, and coal beds. The work focused on sedimentary basins as the initial most-promising targets for geologic sequestration. Geographical Information System (GIS) layers showing sedimentary basins and oil, gas, and coal fields in those basins were developed. The GIS layers were attributed with information on the subsurface, including sediment thickness, presence and depth of porous and permeable sandstones, and, where available, reservoir properties. California offers outstanding sequestration opportunities because of its large capacity and the potential of value-added benefits from enhanced oil recovery (EOR) and enhanced gas recovery (EGR). The estimate for storage capacity of saline formations in the ten largest basins in California ranges from about 150 to about 500 Gt of CO{sub 2}, depending on assumptions about the fraction of the formations used and the fraction of the pore volume filled with separate-phase CO{sub 2}. Potential CO{sub 2}-EOR storage was estimated to be 3.4 Gt, based on a screening of reservoirs using depth, an API gravity cutoff, and cumulative oil produced. The cumulative production from gas reservoirs (screened by depth) suggests a CO{sub 2} storage capacity of 1.7 Gt. In Oregon and Washington, sedimentary basins along the coast also offer sequestration opportunities. Of particular interest is the Puget Trough Basin, which contains up to 1,130 m (3,700 ft) of unconsolidated sediments overlying up to 3,050 m (10,000 ft) of Tertiary sedimentary rocks. The Puget Trough Basin also contains deep coal formations, which are sequestration targets and may have potential for enhanced coal bed methane recovery (ECBM).

Larry Myer

2005-09-29T23:59:59.000Z

196

Methods for geothermal reservoir detection emphasizing submerged environments  

DOE Green Energy (OSTI)

This report has been prepared for the California State Lands Commission to aid them in evaluating exploration programs for geothermal reservoirs, particularly in submerged land environments. Three charts show: (1) a logical progression of specific geologic, geochemical, and geophysical exploration techniques for detecting geothermal reservoirs in various geologic environments with emphasis on submerged lands, (2) various exploration techniques which can be used to develop specific information in geothermal areas, and (3) if various techniques will apply to geothermal exploration according to a detailed geologic classification. A narrative in semi-outline form supplements these charts, providing for each technique; a brief description, advantages, disadvantages, special geologic considerations, and specific references. The specific geologic situation will control the exploration criterion to be used for reservoir detection. General guidelines are established which may be of use in evaluating such a program, but the optimum approach will vary with each situation.

Case, C.W.; Wilde, P.

1976-05-21T23:59:59.000Z

197

A reservoir management strategy for multilayered reservoirs in eastern Venezuela  

E-Print Network (OSTI)

A reservoir management strategy has been developed for a field located in eastern Venezuela. The field contains deep, high pressure, multilayer reservoirs. A thorough formation evaluation was accomplished using the log data, core data, PVT data, geologic data, well completion data and the production data. A reservoir simulation model was built to forecast reservoir performance for a variety of exploitation and well completion strategies. Reserve forecasts have been made using the reservoir model. The methodology applied in this research consists of eight tasks: 1) build a data base with existing data, 2) analyze the log and core data, 3) analyze the pressure and production data, 4) analyze the PVT data, 5) analyze the hydraulic fracture treatments, 6) build the reservoir model, 7) determine the possible reservoir management strategies, and 8) perform economic evaluations for the management strategies. While much of the data for the field studied was supplied by PDVSA, we did not receive all of the data we requested. For example, no pressure buildup data were available. When necessary, we used correlations to determine values for reservoir data that we were not supplied. In this research four formations were studied and characterized, determining porosity and permeability values. Also, fracture treatments were analyzed and a reservoir model was developed. Runs for black oil and volatile oil were performed. The results show that the upper zones are the most prospective areas, but fracture treatments must be performed to reduce the damage on the sand face. Lower formations (Cretaceous) have a lower permeability value, but high OOIP that justify performing fracture treatments and completing this zone. Economics were developed to support this conclusion. Optimum well spacing was calculated showing that 960 acres is the optimum well spacing, but also that 640 acres can be maintained for all the reservoirs and dual completions can be performed, first hydraulic fracturing and completing the Cretaceous formation, and then, completing any upper zone. Reservoir simulation results show that up to 31% of OOIP may be incrementally recovered by hydraulic fracturing the Cretaceous formation and 10 or less from the upper zones.

Espinel Diaz, Arnaldo Leopoldo

1998-01-01T23:59:59.000Z

198

Reservoir Modeling for Production Management  

DOE Green Energy (OSTI)

For both petroleum and geothermal resources, many of the reservoirs are fracture dominated--rather than matrix-permeability controlled. For such reservoirs, a knowledge of the pressure-dependent permeability of the interconnected system of natural joints (i.e., pre-existing fractures) is critical to the efficient exploitation of the resource through proper pressure management. Our experience and that reported by others indicates that a reduction in the reservoir pressure sometimes leads to an overall reduction in production rate due to the ''pinching off'' of the joint network, rather than the anticipated increase in production rate. This effect occurs not just in the vicinity of the wellbore, where proppants are sometimes employed, but throughout much of the reservoir region. This follows from the fact that under certain circumstances, the decline in fracture permeability (or conductivity) with decreasing reservoir pressure exceeds the far-field reservoir ''drainage'' flow rate increase due to the increased pressure gradient. Further, a knowledge of the pressure-dependent joint permeability could aid in designing more appropriate secondary recovery strategies in petroleum reservoirs or reinjection procedures for geothermal reservoirs.

Brown, Donald W.

1989-03-21T23:59:59.000Z

199

Automatic Building of Structured Geological Models Sylvain Brandel1  

E-Print Network (OSTI)

geological models used for oil and gas exploration. We present a prototype of a "geological pilot" which Modeling for oil and gas exploration Hydrocarbon reservoir models are a major tool currently used involved in oil and gas exploration have acquired a huge amount of seismic data, which are neither

Brandel, Sylvain

200

The Ahuachapan geothermal field, El Salvador: Reservoir analysis  

DOE Green Energy (OSTI)

The Earth Sciences Division of Lawrence Berkeley Laboratory (LBL) is conducting a reservoir evaluation study of the Ahuachapan geothermal field in El Salvador. This work is being performed in cooperation with the Comision Ejecutiva Hidroelectrica del Rio Lempa (CEL) and the Los Alamos National Laboratory (LANL). This report describes the work done during the first year of the study (FY 1988--89), and includes the (1) development of geological and conceptual models of the field, (2) evaluation of the initial thermodynamic and chemical conditions and their changes during exploitation, (3) evaluation of interference test data and the observed reservoir pressure decline, and (4) the development of a natural state model for the field. The geological model of the field indicates that there are seven (7) major and five (5) minor faults that control the fluid movement in the Ahuachapan area. Some of the faults act as a barrier to flow as indicated by large temperature declines towards the north and west. Other faults act as preferential pathways to flow. The Ahuachapan Andesites provide good horizontal permeability to flow and provide most of the fluids to the wells. The underlying Older Agglomerates also contribute to well production, but considerably less than the Andesites. 84 refs.

Aunzo, Z.; Bodvarsson, G.S.; Laky, C.; Lippmann, M.J.; Steingrimsson, B.; Truesdell, A.H.; Witherspoon, P.A. (Lawrence Berkeley Lab., CA (USA); Icelandic National Energy Authority, Reykjavik (Iceland); Geological Survey, Menlo Park, CA (USA); Lawrence Berkeley Lab., CA (USA))

1989-08-01T23:59:59.000Z

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201

Storage capacity in hot dry rock reservoirs  

DOE Patents (OSTI)

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

Brown, Donald W. (Los Alamos, NM)

1997-01-01T23:59:59.000Z

202

SEISMIC DETERMINATION OF RESERVOIR HETEROGENEITY: APPLICATION TO THE CHARACTERIZATION OF HEAVY OIL RESERVOIRS  

SciTech Connect

The objective of the project was to examine how seismic and geologic data can be used to improve characterization of small-scale heterogeneity and their parameterization in reservoir models. The study focused on West Coalinga Field in California. The project initially attempted to build reservoir models based on different geologic and geophysical data independently using different tools, then to compare the results, and ultimately to integrate them all. We learned, however, that this strategy was impractical. The different data and tools need to be integrated from the beginning because they are all interrelated. This report describes a new approach to geostatistical modeling and presents an integration of geology and geophysics to explain the formation of the complex Coalinga reservoir.

Matthias G. Imhof; James W. Castle

2005-02-01T23:59:59.000Z

203

SEISMIC DETERMINATION OF RESERVOIR HETEROGENEITY: APPLICATION TO THE CHARACTERIZATION OF HEAVY OIL RESERVOIRS  

SciTech Connect

The objective of the project was to examine how seismic and geologic data can be used to improve characterization of small-scale heterogeneity and their parameterization in reservoir models. The study focused on West Coalinga Field in California. The project initially attempted to build reservoir models based on different geologic and geophysical data independently using different tools, then to compare the results, and ultimately to integrate them all. Throughout the project, however, we learned that this strategy was impractical because the different data and model are complementary instead of competitive. For the complex Coalinga field, we found that a thorough understanding of the reservoir evolution through geologic times provides the necessary framework which ultimately allows integration of the different data and techniques.

Matthias G. Imhof; James W. Castle

2005-02-01T23:59:59.000Z

204

Integrated reservoir study of the 8 reservoir of the Green Canyon 18 field  

E-Print Network (OSTI)

The move into deeper waters in the Gulf of Mexico has produced new opportunities for petroleum production, but it also has produced new challenges as different reservoir problems are encountered. This integrated reservoir characterization effort has provided useful information about the behavior and characteristics of a typical unconsolidated, overpressured, fine-grained, turbidite reservoir, which constitutes the majority of the reservoirs present in the Outer Continental Shelf of the Gulf of Mexico. Reservoirs in the Green Canyon 18 (GC 18) field constitute part of a turbidite package with reservoir quality typically increasing with depth. Characterization of the relatively shallow 8 reservoir had hitherto been hindered by the difficulty in resolving its complex architecture and stratigraphy. Furthermore, the combination of its unconsolidated rock matrix and abnormal pore pressure has resulted in severe production-induced compaction. The reservoir's complex geology had previously obfuscated the delineation of its hydrocarbon accumulation and determination of its different resource volumes. Geological and architectural alterations caused by post-accumulation salt tectonic activities had previously undermined the determination of the reservoir's active drive mechanisms and their chronology. Seismic interpretation has provided the reservoir geometry and topography. The reservoir stratigraphy has been defined using log, core and seismic data. With well data as pilot points, the spatial distribution of the reservoir properties has been defined using geostatistics. The resulting geological model was used to construct a dynamic flow model that matched historical production and pressure data.. The reservoir's pressure and production behavior indicates a dominant compaction drive mechanism. The results of this work show that the reservoir performance is influenced not only by the available drive energy, but also by the spatial distribution of the different facies relative to well locations. The study has delineated the hydrocarbon bearing reservoir, quantified the different resource categories as STOIIP/GIIP = 19.8/26.2 mmstb/Bscf, ultimate recovery = 9.92/16.01 mmstb/Bscf, and reserves (as of 9/2001) = 1.74/5.99 mmstb/Bscf of oil and gas, respectively. There does not appear to be significant benefit to infill drilling or enhanced recovery operations.

Aniekwena, Anthony Udegbunam

2003-08-01T23:59:59.000Z

205

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

Science Conference Proceedings (OSTI)

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.

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

1999-04-05T23:59:59.000Z

206

Mapping of Reservoir Properties and Facies Through Integration of Static and Dynamic Data  

Science Conference Proceedings (OSTI)

The goal of this project was 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.

Oliver, Dean S.; Reynolds, Albert C.; Zhang, Fengjun; Li, Ruijian; Abacioglu, Yafes; Dong, Yannong

2002-03-05T23:59:59.000Z

207

Application of integrated reservoir management and reservoir characterization to optimize infill drilling. Annual report, June 13, 1994--June 12, 1995  

SciTech Connect

This project has used a multi-disciplinary approach employing geology, geophysics, and engineering to conduct advanced reservoir characterization and management activities to design and implement an optimized infill drilling program at the North Robertson (Clearfork) Unit in Gaines County, Texas. The activities during the first Budget Period have consisted of developing an integrated reservoir description from geological, engineering, and geostatistical studies, and using this description for reservoir flow simulation. Specific reservoir management activities are being identified and tested. The geologically targeted infill drilling program will be implemented using the results of this work. A significant contribution of this project is to demonstrate the use of cost-effective reservoir characterization and management tools that will be helpful to both independent and major operators for the optimal development of heterogeneous, low permeability shallow-shelf carbonate (SSC) reservoirs. The techniques that are outlined for the formulation of an integrated reservoir description apply to all oil and gas reservoirs, but are specifically tailored for use in the heterogeneous, low permeability carbonate reservoirs of West Texas.

Pande, P.K.

1996-11-01T23:59:59.000Z

208

Fractured reservoir characterization through injection, falloff, and flowback tests  

SciTech Connect

This paper presents the development of a multiphase pressure-transient-analysis technique for naturally fractured reservoirs and the analysis of a series of field tests performed to evaluate the water injection potential and the reservoir characteristics of a naturally fractured reservoir. These included step-rate, water-injectivity, pressure-falloff, and flowback tests. Through these tests, a description of the reservoir was obtained.

Peng, C.P.; Singh, P.K. (Amoco Production Co., Tulsa, OK (United States)); Halvorsen, H. (Amoco Norway Oil Co., Stavanger (NO)); York, S.D. (Amoco Production Co., Houston, TX (United States))

1992-09-01T23:59:59.000Z

209

Reservoir characterization, performance monitoring of waterflooding and development opportunities in Germania Spraberry Unit.  

E-Print Network (OSTI)

The Germania Unit is located in Midland County, 12 miles east of Midland, Texas and is part of the Spraberry Formation in the Midland Basin which is one of the largest known oil reservoirs in the world bearing between 8.9 billion barrels and 10.5 billion barrels of oil originally in place. The field is considered geologically complex since it comprises typically low porosity, low permeability fine sandstones, and siltstones that are interbedded with shaly non-reservoir rocks. Natural fractures existing over a regional area have long been known to dominate all aspects of performance in the Spraberry Trend Area. Two stages of depletion have taken place over 46 years of production: Primary production under solution gas drive and secondary recovery via water injection through two different injection patterns. The cumulative production and injection in Germania as of July 2003 were 3.24 million barrels and 3.44 million barrels respectively and the production level is 470 BOPD through 64 active wells with an average rate per well of 7.3 BOPD and average water cut of 60 percent. This performance is considered very low and along with the low amount of water injected, waterflood recovery has never been thoroughly understood. In this research, production and injection data were analyzed and integrated to optimize the reservoir management strategies for Germania Spraberry Unit. This study addresses reservoir characterization and monitoring of the waterflood project with the aim of proposing alternatives development, taking into account current and future conditions of the reservoir. Consequently, this project will be performed to provide a significant reservoir characterization in an uncharacterized area of Spraberry and evaluate the performance of the waterflooding to provide facts, information and knowledge to obtain the maximum economic recovery from this reservoir and finally understand waterflood management in Spraberry. Thus, this research describes the reservoir, and comprises the performance of the reservoir under waterflooding, and controlled surveillance to improve field performance. This research should serve as a guide for future work in reservoir simulation and reservoir management and can be used to evaluate various scenarios for additional development as well as to optimize the operating practices in the field. The results indicate that under the current conditions, a total of 1.410 million barrels of oil can be produced in the next 20 years through the 64 active wells and suggest that the unit can be successfully flooded with the current injection rate of 1600 BWPD and pattern consisting of 6 injection wells aligned about 36 degrees respect to the major fracture orientation. This incremental is based in both extrapolations and numerical simulation studies conducted in Spraberry.

Hernandez Hernandez, Erwin Enrique

2003-05-01T23:59:59.000Z

210

Selection of best drilling, completion and stimulation method for coalbed methane reservoirs  

E-Print Network (OSTI)

Over the past three decades, coalbed methane (CBM) has moved from a mining hazard and novel unconventional resource to an important fossil fuel that accounts for approximately 10% of the U.S. natural gas production and reserves. The expansion of this industry required development of different drilling, completion and stimulation practices for CBM in specific North American basins, owing to the complex combinations of geologic settings and reservoir parameters encountered. These challenges led to many technology advances and to development of CBM drilling, completion and stimulation technology for specific geologic settings. The objectives of this study were to (1) determine which geologic parameters affect CBM drilling, completion and stimulation decisions, (2) identify to the engineering best practices for specific geologic settings, and (3) present these findings in decision charts or advisory systems that could be applied by industry professionals. To determine best drilling, completion and stimulation practices for CBM reservoirs, I reviewed literature and solicited opinions of industry experts through responses to a questionnaire. I identified thirteen geologic parameters (and their ranges of values) that are assessed when selecting CBM drilling, completion and stimulating applications. These are coal thickness, number of seams, areal extent, dip, depth, rank, gas content, formation pressure, permeability, water saturation, and compressive strength, as well as the vertical distribution of coal beds and distance from coal reservoirs to fracture barriers or aquifers. Next, I identified the optimum CBM drilling, completion and stimulating practices for specific combinations of these geologic parameters. The engineering best practices identified in this project may be applied to new or existing fields, to optimize gas reserves and project economics. I identified the best engineering practices for the different CBM basins in N.A and combined these results in the form of two decision charts that engineers may use to select best drilling and completion practices, as well as the optimal stimulation methods and fluids for specific geologic settings. The decision charts are presented in a Visual Basic Application software program to facilitate their use by engineers.

Ramaswamy, Sunil

2007-12-01T23:59:59.000Z

211

Gulf of Mexico Federal Offshore - Louisiana and Alabama Dry Natural...  

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

Dry Natural Gas New Reservoir Discoveries in Old Fields (Billion Cubic Feet) Gulf of Mexico Federal Offshore - Louisiana and Alabama Dry Natural Gas New Reservoir Discoveries in...

212

Geology Of The Fenton Hill, New Mexico, Hot Dry Rock Site | Open Energy  

Open Energy Info (EERE)

source source History View New Pages Recent Changes All Special Pages Semantic Search/Querying Get Involved Help Apps Datasets Community Login | Sign Up Search Page Edit History Facebook icon Twitter icon » Geology Of The Fenton Hill, New Mexico, Hot Dry Rock Site Jump to: navigation, search GEOTHERMAL ENERGYGeothermal Home Journal Article: Geology Of The Fenton Hill, New Mexico, Hot Dry Rock Site Details Activities (4) Areas (1) Regions (0) Abstract: The Phase I prototype hot dry rock (HDR) geothermal system was developed in Precambrian basement rocks at Fenton Hill, New Mexico. Core and cuttings samples from the four deep wells indicate that the reservoir of this Phase I HDR system lies within a homogeneous biotite granodiorite body of very low permeability. Natural fractures, although present, are

213

NETL: Geological and Environmental Science  

NLE Websites -- All DOE Office Websites (Extended Search)

Geological & Environmental Systems Geological & Environmental Systems Onsite Research Geological and Environmental Sciences Geological and Environmental Sciences (GES) is a focus area of the National Energy Technology Laboratory's Office of Research and Development (ORD). ORD's other focus areas are Energy System Dynamics, Computational and Basic Sciences, and Materials Science and Engineering. Scientists and engineers in ORD conduct research at NETL's advanced research facilities in Morgantown, WV; Pittsburgh, PA; and Albany, OR, and at various offsite locations. GES tackles the challenge of clean energy production from fossil energy sources by focusing on the behavior of natural systems at both the earth's surface and subsurface, including prediction, control, and monitoring of fluid flow in porous and fractured media. Efforts include

214

Seismic Determination of Reservoir Heterogeneity: Application to the Characterization of Heavy Oil Reservoirs  

SciTech Connect

The objective of the project was to examine how seismic and geologic data could be used to improve characterization of small-scale heterogeneity and their parameterization in reservoir models. Performed a theoretical and numerical study to examine which subsurface features the surface seismic method actually resolves.

Imhof, Matthias G.; Castle, James W.

2003-03-12T23:59:59.000Z

215

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

Science Conference Proceedings (OSTI)

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 1940s 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 1940s 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

Hanks, Catherine

2012-12-31T23:59:59.000Z

216

Natural Gas Monthly  

Annual Energy Outlook 2012 (EIA)

Gas: Gas in place at the time that a reservoir was converted to use as an underground storage reservoir, as in contrast to injected gas volumes. Natural Gas: A gaseous mixture...

217

System-level modeling for geological storage of CO2  

E-Print Network (OSTI)

4 ) reservoir, a natural gas power plant that burns CH 4 ,2 produced from the natural gas power plant, there are twoflue gas of the natural gas power plant in the system. When

Zhang, Yingqi; Oldenburg, Curtis M.; Finsterle, Stefan; Bodvarsson, Gudmundur S.

2006-01-01T23:59:59.000Z

218

A life cycle cost analysis framework for geologic storage of hydrogen : a user's tool.  

DOE Green Energy (OSTI)

The U.S. Department of Energy (DOE) has an interest in large scale hydrogen geostorage, which could offer substantial buffer capacity to meet possible disruptions in supply or changing seasonal demands. The geostorage site options being considered are salt caverns, depleted oil/gas reservoirs, aquifers and hard rock caverns. The DOE has an interest in assessing the geological, geomechanical and economic viability for these types of geologic hydrogen storage options. This study has developed an economic analysis methodology and subsequent spreadsheet analysis to address costs entailed in developing and operating an underground geologic storage facility. This year the tool was updated specifically to (1) incorporate more site-specific model input assumptions for the wells and storage site modules, (2) develop a version that matches the general format of the HDSAM model developed and maintained by Argonne National Laboratory, and (3) incorporate specific demand scenarios illustrating the model's capability. Four general types of underground storage were analyzed: salt caverns, depleted oil/gas reservoirs, aquifers, and hard rock caverns/other custom sites. Due to the substantial lessons learned from the geological storage of natural gas already employed, these options present a potentially sizable storage option. Understanding and including these various geologic storage types in the analysis physical and economic framework will help identify what geologic option would be best suited for the storage of hydrogen. It is important to note, however, that existing natural gas options may not translate to a hydrogen system where substantial engineering obstacles may be encountered. There are only three locations worldwide that currently store hydrogen underground and they are all in salt caverns. Two locations are in the U.S. (Texas), and are managed by ConocoPhillips and Praxair (Leighty, 2007). The third is in Teeside, U.K., managed by Sabic Petrochemicals (Crotogino et al., 2008; Panfilov et al., 2006). These existing H{sub 2} facilities are quite small by natural gas storage standards. The second stage of the analysis involved providing ANL with estimated geostorage costs of hydrogen within salt caverns for various market penetrations for four representative cities (Houston, Detroit, Pittsburgh and Los Angeles). Using these demand levels, the scale and cost of hydrogen storage necessary to meet 10%, 25% and 100% of vehicle summer demands was calculated.

Kobos, Peter Holmes; Lord, Anna Snider; Borns, David James; Klise, Geoffrey T.

2011-09-01T23:59:59.000Z

219

Please cite this article in press as: Gilfillan, S.M.V., et al., He and Ne as tracers of natural CO2 migration up a fault from a deep reservoir. Int. J. Greenhouse Gas Control (2011), doi:10.1016/j.ijggc.2011.08.008  

E-Print Network (OSTI)

of Greenhouse Gas Control journal homepage: www.elsevier.com/locate/ijggc He and Ne as tracers of natural CO22 Noble gases Carbon isotopes Geological storage of CO2 Natural analogues a b s t r a c t Capture that could arise from a diffuse leakage of CO2 from a storage site. This is because there are many natural

220

Natural CO2 Analogs for Carbon Sequestration  

Science Conference Proceedings (OSTI)

The report summarizes research conducted at three naturally occurring geologic CO{sub 2} fields in the US. The fields are natural analogs useful for the design of engineered long-term storage of anthropogenic CO{sub 2} in geologic formations. Geologic, engineering, and operational databases were developed for McElmo Dome in Colorado; St. Johns Dome in Arizona and New Mexico; and Jackson Dome in Mississippi. The three study sites stored a total of 2.4 billion t (46 Tcf) of CO{sub 2} equivalent to 1.5 years of power plant emissions in the US and comparable in size with the largest proposed sequestration projects. The three CO{sub 2} fields offer a scientifically useful range of contrasting geologic settings (carbonate vs. sandstone reservoir; supercritical vs. free gas state; normally pressured vs. overpressured), as well as different stages of commercial development (mostly undeveloped to mature). The current study relied mainly on existing data provided by the CO{sub 2} field operator partners, augmented with new geochemical data. Additional study at these unique natural CO{sub 2} accumulations could further help guide the development of safe and cost-effective design and operation methods for engineered CO{sub 2} storage sites.

Scott H. Stevens; B. Scott Tye

2005-07-31T23:59:59.000Z

Note: This page contains sample records for the topic "natural geological reservoir" from the National Library of EnergyBeta (NLEBeta).
While these samples are representative of the content of NLEBeta,
they are not comprehensive nor are they the most current set.
We encourage you to perform a real-time search of NLEBeta
to obtain the most current and comprehensive results.


221

Impact of geologic parameters on enhanced oil recovery - workshop proceedings  

SciTech Connect

The purpose of this workshop is to identify and develop objectives for future geologic research needed to increase light oil production with the enhanced oil recovery processes and to identify quantitative studies with potential to predict the impact reservoir heterogeneities on the light oil recovery processes. With these goals in mind, four workshop groups were organized to discuss and develop a conceptual R and D program to minimize the geologic constraints to E.O.R. These workshop groups will provide guidance and input into DOE's light oil research program and will help decide where time and resources are most effectively utilized. Working groups studied: (1) rock-fluid interactions; (2) reservoir heterogeneity; (3) reservoir description; and (4) geologic imput into EOR simulation studies. The question addressed is whether the present technology is adequate to quantitatively define each of these areas for predictive uses. If it is not, what techniques and instrumentation is necessary to define these for each EOR process.

Peterson, M.

1982-05-01T23:59:59.000Z

222

Definition: Hydrothermal Reservoir | Open Energy Information  

Open Energy Info (EERE)

Hydrothermal Reservoirs are underground zones of porous rock containing hot water and steam, and can be naturally occurring or human-made.1 References x Ret LikeLike...

223

PROCEEDINGS TWENTIETH WORKSHOP GEOTHERMAL RESERVOIR ENGINEERING  

NLE Websites -- All DOE Office Websites (Extended Search)

a global reservoir value of the amount of adsorbed liquid water per kg of rock (called ADS in the present paper). We simulated the natural state with different values of ADS,...

224

Naturally fractured reservoirs: Optimized E and P strategies using a reaction-transport-mechanical simulator in an integrated approach. Annual report, 1996--1997  

SciTech Connect

The methodology and results of this project are being tested using the Andector-Goldsmith Field in the Permian Basin, West Texas. The study area includes the Central Basin Platform and the Midland Basin. The Andector-Goldsmith Field lies at the juncture of these two zones in the greater West Texas Permian Basin. Although the modeling is being conducted in this area, the results have widespread applicability to other fractured carbonate and other reservoirs throughout the world.

Hoak, T.; Jenkins, R. [Science Applications International Corp., McLean, VA (United States); Ortoleva, P.; Ozkan, G.; Shebl, M.; Sibo, W.; Tuncay, K. [Laboratory for Computational Geodynamics (United States); Sundberg, K. [Phillips Petroleum Company (United States)

1998-07-01T23:59:59.000Z

225

Natural and industrial analogues for release of CO2 from storage reservoirs: Identification of features, events, and processes and lessons learned  

E-Print Network (OSTI)

oil, natural gas, and gas turbine power plants. As shown,Flue Flue Flue Fuel oil Natural gas Natural gas Gas turbineGas turbine Gas turbine Coal IGCC Flue Flue Flue Flue Fuel

Lewicki, Jennifer L.; Birkholzer, Jens; Tsang, Chin-Fu

2006-01-01T23:59:59.000Z

226

PROCEEDINGS, Thirty-Sixth Workshop on Geothermal Reservoir Engineering Stanford University, Stanford, California, January 31 -February 2, 2011  

E-Print Network (OSTI)

PROCEEDINGS, Thirty-Sixth Workshop on Geothermal Reservoir Engineering Stanford University Berkeley, California 94720 e-mail: Kboyle@lbl.gov ABSTRACT The Geysers Geothermal Reservoir experiences, and processing system. INTRODUCTION Geological Setting The Geysers geothermal reservoir is located just south

Stanford University

227

Final report of the Department of Energy Reservoir Definition Review Team for the Baca Geothermal Demonstration Project  

DOE Green Energy (OSTI)

The Baca project was terminated due to inability to find sufficient steam production to support the power plant. The following aspects of the project are discussed: regional geology; structure, stratigraphy, and permeability in the Redondo Creek; geophysics; geochemical indicators of reservoir conditions; drilling problems; fracture stimulation experiments; reservoir definition and conceptual model; and prediction of reservoir performance.

Goldstein, N.E.; Holman, W.R.; Molloy, M.W. (eds.)

1982-06-01T23:59:59.000Z

228

A life cycle cost analysis framework for geologic storage of hydrogen : a scenario analysis.  

DOE Green Energy (OSTI)

The U.S. Department of Energy has an interest in large scale hydrogen geostorage, which would offer substantial buffer capacity to meet possible disruptions in supply. Geostorage options being considered are salt caverns, depleted oil/gas reservoirs, aquifers and potentially hard rock cavrns. DOE has an interest in assessing the geological, geomechanical and economic viability for these types of hydrogen storage options. This study has developed an ecocomic analysis methodology to address costs entailed in developing and operating an underground geologic storage facility. This year the tool was updated specifically to (1) a version that is fully arrayed such that all four types of geologic storage options can be assessed at the same time, (2) incorporate specific scenarios illustrating the model's capability, and (3) incorporate more accurate model input assumptions for the wells and storage site modules. Drawing from the knowledge gained in the underground large scale geostorage options for natural gas and petroleum in the U.S. and from the potential to store relatively large volumes of CO{sub 2} in geological formations, the hydrogen storage assessment modeling will continue to build on these strengths while maintaining modeling transparency such that other modeling efforts may draw from this project.

Kobos, Peter Holmes; Lord, Anna Snider; Borns, David James

2010-10-01T23:59:59.000Z

229

On leakage and seepage from geological carbon sequestration sites  

SciTech Connect

Geologic carbon sequestration is one strategy for reducing the rate of increase of global atmospheric carbon dioxide (CO{sub 2} ) concentrations (IEA, 1997; Reichle, 2000). As used here, the term geologic carbon sequestration refers to the direct injection of supercritical CO{sub 2} deep into subsurface target formations. These target formations will typically be either depleted oil and gas reservoirs, or brine-filled permeable formations referred to here as brine formations. Injected CO{sub 2} will tend to be trapped by one or more of the following mechanisms: (1) permeability trapping, for example when buoyant supercritical CO{sub 2} rises until trapped by a confining caprock; (2) solubility trapping, for example when CO{sub 2} dissolves into the aqueous phase in water-saturated formations, or (3) mineralogic trapping, such as occurs when CO{sub 2} reacts to produce stable carbonate minerals. When CO{sub 2} is trapped in the subsurface by any of these mechanisms, it is effectively sequestered away from the atmosphere where it would otherwise act as a greenhouse gas. The purpose of this report is to summarize our work aimed at quantifying potential CO{sub 2} seepage due to leakage from geologic carbon sequestration sites. The approach we take is to present first the relevant properties of CO{sub 2} over the range of conditions from the deep subsurface to the vadose zone (Section 2), and then discuss conceptual models for how leakage might occur (Section 3). The discussion includes consideration of gas reservoir and natural gas storage analogs, along with some simple estimates of seepage based on assumed leakage rates. The conceptual model discussion provides the background for the modeling approach wherein we focus on simulating transport in the vadose zone, the last potential barrier to CO{sub 2} seepage (Section 4). Because of the potentially wide range of possible properties of actual future geologic sequestration sites, we carry out sensitivity analyses by means of numerical simulation and derive the trends in seepage flux and near-surface CO{sub 2} concentrations that will arise from variations in fundamental hydrogeological properties.

Oldenburg, C.M.; Unger, A.J.A.; Hepple, R.P.; Jordan, P.D.

2002-07-18T23:59:59.000Z

230

Miscellaneous States Shale Gas Proved Reserves New Reservoir...  

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

to avoid disclosure of individual company data. Release Date: 812013 Next Release Date: 812014 Referring Pages: Shale Natural Gas New Reservoir Discoveries in Old Fields...

231

Horizontal Well Placement Optimization in Gas Reservoirs Using Genetic Algorithms  

E-Print Network (OSTI)

Horizontal well placement determination within a reservoir is a significant and difficult step in the reservoir development process. Determining the optimal well location is a complex problem involving many factors including geological considerations, reservoir and fluid properties, economic costs, lateral direction, and technical ability. The most thorough approach to this problem is that of an exhaustive search, in which a simulation is run for every conceivable well position in the reservoir. Although thorough and accurate, this approach is typically not used in real world applications due to the time constraints from the excessive number of simulations. This project suggests the use of a genetic algorithm applied to the horizontal well placement problem in a gas reservoir to reduce the required number of simulations. This research aims to first determine if well placement optimization is even necessary in a gas reservoir, and if so, to determine the benefit of optimization. Performance of the genetic algorithm was analyzed through five different case scenarios, one involving a vertical well and four involving horizontal wells. The genetic algorithm approach is used to evaluate the effect of well placement in heterogeneous and anisotropic reservoirs on reservoir recovery. The wells are constrained by surface gas rate and bottom-hole pressure for each case. This project's main new contribution is its application of using genetic algorithms to study the effect of well placement optimization in gas reservoirs. Two fundamental questions have been answered in this research. First, does well placement in a gas reservoir affect the reservoir performance? If so, what is an efficient method to find the optimal well location based on reservoir performance? The research provides evidence that well placement optimization is an important criterion during the reservoir development phase of a horizontal-well project in gas reservoirs, but it is less significant to vertical wells in a homogeneous reservoir. It is also shown that genetic algorithms are an extremely efficient and robust tool to find the optimal location.

Gibbs, Trevor Howard

2010-05-01T23:59:59.000Z

232

NETL: Oil & Natural Gas Technologies Reference Shelf - Presentation  

NLE Websites -- All DOE Office Websites (Extended Search)

Designing a Pilot-Scale Experiment for the Production of Natural Gas Hydrates and Sequestration of CO2 in Geologic Reservoirs Designing a Pilot-Scale Experiment for the Production of Natural Gas Hydrates and Sequestration of CO2 in Geologic Reservoirs Designing a Pilot-Scale Experiment for the Production of Natural Gas Hydrates and Sequestration of CO2 in Geologic Reservoirs Authors: Mark White and Pete McGrail Venue: The 9th International Conference on Greenhouse Gas Technologies will be held November 16-20, 2008 at The Omni Shoreham Hotel in Washington, DC. The Conference will be organized by MIT in collaboration with the IEA Greenhouse Gas R&D Programme (IEA GHG), with major sponsorship from the US Department of Energy. http://mit.edu/ghgt9/ . Abstract: Under high pressure and low temperature conditions small nonpolar molecules (typically gases) can combine with water to form crystalline structures known as clathrate hydrates. Methane (CH4) and carbon dioxide (CO2) form nearly identical clathrate structures (sI), with the CO2 hydrate being thermodynamically favored. Vast accumulations of methane hydrates have been found in suboceanic deposits and beneath the arctic permafrost. Because of the large volumetric storage densities, clathrate hydrates on the deep ocean floor have been suggested as a sequestration option for CO2. Alternatively, CO2 hydrates can be formed in the geologic settings of naturally occurring accumulations of methane hydrates. Global assessments of natural gas resources have shown that gas hydrate resources exceed those of conventional resources, which is indicative of the potential for clathrate hydrate sequestration of CO2. Recovery of natural gas from hydrate-bearing geologic deposits has the potential for being economically viable, but there remain significant technical challenges in converting these natural accumulations into a useable resource. Currently, conventional methods for producing methane hydrates from geologic settings include depressurization, thermal stimulation, and inhibitor injection. Although CO2 clathrates generally are not naturally as abundant as those of CH4, their occurrence forms the foundation of an unconventional approach for producing natural gas hydrates that involves the exchange of CO2 with CH4 in the hydrate structure. This unconventional concept has several distinct benefits over the conventional methods: 1) the heat of formation of CO2 hydrate is greater than the heat of dissociation of CH4 hydrate, providing a low-grade heat source to support additional methane hydrate dissociation, 2) exchanging CO2 with CH4 will maintain the mechanical stability of the geologic formation, and 3) the process is environmentally friendly, providing a sequestration mechanism for the injected CO2. The exchange production technology would not be feasible without the favorable thermodynamics of CO2 hydrates over CH4 hydrates. This situation yields challenges for the technology to avoid secondary hydrate formation and clogging of the geologic repository. Laboratory-scale experiments have demonstrated the feasibility of producing natural gas and sequestering CO2 using the direct exchange technology in geologic media. These experiments have duplicated numerically using the STOMP-HYD simulator, which solves the nonisothermal multifluid flow and transport equations for mixed hydrate systems in geologic media. This paper describes the design (via numerical simulation) of a pilot-scale demonstration test of the CO2 exchange production and sequestration technology for a geologic setting beneath the arctic permafrost, involving a gas-hydrate interval overlying a free-gas interval (i.e., Class 1 Hydrate Accumulation).

233

Estimation of hydrologic properties of heterogeneous geologic media with an inverse method based on iterated function systems  

Science Conference Proceedings (OSTI)

The highly heterogeneous nature of most geologic media, coupled with the restricted view of the subsurface available through boreholes, makes it difficult to determine the spatial distribution of subsurface hydrologic properties. Without such a description one cannot predict how fluid flow or solute transport will occur through permeable geologic media, and these predictions are critically needed to address many important environmental problems, including toxic chemical spills, leaking underground storage tanks, and long-term radioactive waste isolation. A common concern of these problems is the possible existence of high-permeability pathways connecting the problem to the biosphere. An understanding of flow and transport behavior is also necessary to optimize energy extraction from petroleum or geothermal reservoirs, where identifying low-permeability barriers that compartmentalize reservoirs and hamper efficient resource utilization is a key problem. The present work describes the development and application of a new inverse method for determining the spatial distribution of hydrologic properties (permeability and specific storage) in heterogeneous geologic media, using pressure transients from interference well tests. The method employs fractal concepts to improve efficiency and reliability. It is applicable to any sort of heterogeneous geologic medium in which wells communicate with each other, whether it be porous, fractured, or a combination thereof. Application to field data from a shallow aquifer at Kesterson Reservoir agrees well with an independent analysis using traditional well-test analysis methods. Application to a series of interference tests conducted at the Gypsy Pilot Site produces a detailed picture of the subsurface, which compares favorably with cross-well seismic imaging studies. 53 refs.

Doughty, C. [Univ. of California, Berkeley, CA (United States). Dept. of Materials Science and Mineral Engineering]|[Lawrence Berkeley Lab., CA (United States). Earth Sciences Div.

1995-12-01T23:59:59.000Z

234

Comprehensive Analysis of Enhanced CBM Production via CO2 Injection Using a Surrogate Reservoir Model Jalal Jalali, Shahab D. Mohaghegh, Dept. of Petroleum & Natural Gas Engineering, West Virginia University  

E-Print Network (OSTI)

a Response Surface Model using Experimental Design technique or using Reduced Models. Once trained, SRMs canComprehensive Analysis of Enhanced CBM Production via CO2 Injection Using a Surrogate Reservoir Reservoir simulation is the industry standard for reservoir management. Complex reservoir models usually

Mohaghegh, Shahab

235

Geological Carbon Sequestration, Spelunking and You | Department of Energy  

Energy.gov (U.S. Department of Energy (DOE)) Indexed Site

Geological Carbon Sequestration, Spelunking and You Geological Carbon Sequestration, Spelunking and You Geological Carbon Sequestration, Spelunking and You August 11, 2010 - 2:45pm Addthis Niketa Kumar Niketa Kumar Public Affairs Specialist, Office of Public Affairs What does this project do? Develops and tests technologies to store CO2 in oil and gas reservoirs, deep saline formations, and basalts Here's a riddle for you: What do spelunkers, mineralogists and the latest Carbon Capture and Sequestration (CCS) awardees have in common? They're all experts in tapping into projects of geological proportions! Today, Secretary Chu announced the selection of 15 projects aimed at developing and testing technologies to store CO2 in oil and gas reservoirs, deep saline formations, and basalts (just to name a few). Funded with $21.3

236

Geological Carbon Sequestration, Spelunking and You | Department of Energy  

Energy.gov (U.S. Department of Energy (DOE)) Indexed Site

Geological Carbon Sequestration, Spelunking and You Geological Carbon Sequestration, Spelunking and You Geological Carbon Sequestration, Spelunking and You August 11, 2010 - 2:45pm Addthis Niketa Kumar Niketa Kumar Public Affairs Specialist, Office of Public Affairs What does this project do? Develops and tests technologies to store CO2 in oil and gas reservoirs, deep saline formations, and basalts Here's a riddle for you: What do spelunkers, mineralogists and the latest Carbon Capture and Sequestration (CCS) awardees have in common? They're all experts in tapping into projects of geological proportions! Today, Secretary Chu announced the selection of 15 projects aimed at developing and testing technologies to store CO2 in oil and gas reservoirs, deep saline formations, and basalts (just to name a few). Funded with $21.3

237

United States Geological Survey Geospatial Information Response  

E-Print Network (OSTI)

requirements, capabilities, and operations in response to a natural or man-made disaster1 United States Geological Survey Geospatial Information Response Information Response Team (GIRT) Standard Operating Procedures (SOP) contains the GIRT

Fleskes, Joe

238

The Rosetta Resources CO2 Storage Project - A WESTCARB Geologic Pilot Test  

E-Print Network (OSTI)

and testing the wells. Capay Shale Gas Reservoir Pilot Thewithin the Middle Capay shale Figure 3. Typical geologic2 is in the Middle Capay Shale. at a depth of 928 m (3044

2006-01-01T23:59:59.000Z

239

Evaluation of a complex sandstone reservoir for EOR  

Science Conference Proceedings (OSTI)

The South Cuyama reservoir is a mature field in California that has both complex geology and a complex operational history. Two factors were considered to be critical in determining the viability of a proposed micellar-polymer flooding process in South Cuyama. first, the faulted nature of the field emphasized the importance of sand continuity between injectors and producers. second, in order to make the estimated oil recovery (EOR) process profitable, the remaining oil had to be large enough to justify the added expense of process implementation. A multidisciplinary study of the South Cuyama field was undertaken by engineers, geologists, and geophysicists from research, engineering, and operations organizations. An initial review of reservoir and production data indicated an expected remaining oil saturation of 35-40% based on an OOIP estimate of 450-510 MMSTB. A geological/geophysical study, including a high-resolution three-dimensional seismic survey, indicated that reasonably good sand continuity was hampered by the occurrence of numerous small faults previously unrecognized by mapping with well data alone. Log-Inject-Log and Single Well Tracer tests were undertaken in several existing wells to determine the remaining oil saturation. A new well was drilled and extensively cored indicating remaining oil saturation in the 9-21% range. Using the new data, an OOIP was recalculated to be 390 MMSTB, 24% less than the original estimate. The results of the study indicated that South Cuyama was not a good candidate for micellar-polymer flooding. The methodology presented here resulted in the determination of this fact without actually running a pilot test, thereby saving considerable expense.

Pathak, P. (ARCO International, Jakarta (Indonesia)); Kuch, K.D.; Moorefield, T.P. (ARCO Oil and Gas Co., Bakersfield, CA (United States)); Kriel, B.G.; Pasternack, E.S.; Ligon, J.H. (ARCO Oil and Gas Co., Plano, TX (United States)); Salter, S.J. (ARCO Oil and Gas Co., Midland, TX (United States))

1991-02-01T23:59:59.000Z

240

Short note: A FORTRAN program to introduce field-measured sedimentary logs into reservoir modelling packages  

Science Conference Proceedings (OSTI)

Building reservoir-scale facies models of outcrops is a practice that improves the three-dimensional geological modelling of subsurface analogues. Facies modelling of outcrops can be achieved either with geostatistical or object-based methods, which ...

O. Falivene; P. Arbus; J. Howell; O. Fernndez; P. Cabello; J. A. Muoz; L. Cabrera

2006-11-01T23:59:59.000Z

Note: This page contains sample records for the topic "natural geological reservoir" from the National Library of EnergyBeta (NLEBeta).
While these samples are representative of the content of NLEBeta,
they are not comprehensive nor are they the most current set.
We encourage you to perform a real-time search of NLEBeta
to obtain the most current and comprehensive results.


241

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

SciTech Connect

The purpose of this work was 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.

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

2002-05-21T23:59:59.000Z

242

Characterization of oil and gas reservoir heterogeneity. Technical progress report, July 1, 1991--September 30, 1991  

SciTech Connect

The ultimate objective of this cooperative research project is to characterize Alaskan petroleum reservoirs in terms of their reserves, physical and chemical properties, geologic configuration in relation to lithofacies and structure, and development potential. The project has two tasks: Task 1 is a geological description of the reservoirs including petrophysical properties, i.e., porosity, permeability, permeability variation, formation depth, temperature, and net pay, facies changes and reservoir structures as drawn from cores, well logs, and other geological data. Task 2 is reservoir fluid characterization -- determination of physical properties of reservoir fluids including density, viscosity, phase distributions and composition as well as petrogenesis -- source rock identification; and the study of asphaltene precipitation for Alaskan crude oils.

Sharma, G.D.

1991-12-31T23:59:59.000Z

243

Characterization of oil and gas reservoir heterogeneity. [Quarterly report], January 1, 1993--March 31, 1993  

SciTech Connect

The ultimate objective of this cooperative research project is to characterize Alaskan petroleum reservoirs in terms of their reserves, physical and chemical properties, geologic configuration in relation to lithofacies and structure, and development potential. The project has two tasks: Task I is a geological description of the reservoirs including petrophysical properties, i.e., porosity, permeability, permeability variation, formation depth, temperature, and net pay, facies changes and reservoir structures as drawn from cores, well logs, and other geological data. Task 2 is reservoir fluid characterization--determination of physical properties of reservoir fluids including density, viscosity, phase distributions and composition as well as petrogenesis--source rock identification; and the study of asphaltene precipitation for Alaskan crude oils.

Sharma, G.D.

1993-04-01T23:59:59.000Z

244

Characterization of oil and gas reservoir heterogeneity. Technical progress report, July 1, 1992--September 30, 1992  

SciTech Connect

The ultimate oojective of this cooperative research project is to characterize Alaskan petroleum reservoirs in terms of their reserves, physical and chemical properties, geologic configuration in relation to lithofacies and structure, and development potential. The project has two tasks: Task 1 is a geological description of the reservoirs including petrophysical properties, i.e., porosity, permeability, permeability variation, formation depth, temperature, and net pay, facies changes and reservoir structures as drawn from cores, well logs, and other geological data. Task 2 is reservoir fluid characterization--determination of physical properties of reservoir fluids including density, viscosity, phase distributions and composition as well as petrogenesis--source rock identification; and the study of asphaltene precipitation for Alaskan crude oils. This report presents a summary of technical progress of the well log analysis of Kuparuk Field, Northslope, Alaska.

Sharma, G.D.

1992-12-01T23:59:59.000Z

245

Characterization of oil and gas reservoir heterogeneity. Technical progress report, October 1, 1991--December 31, 1991  

SciTech Connect

The ultimate objective of this cooperative research project is to characterize Alaskan petroleum reservoirs in terms of their reserves, physical and chemical properties, geologic configuration in relation to lithofacies and structure, and development potential. The project has two tasks: Task 1 is a geological description of the reservoirs including petrophysical properties, i.e., porosity, permeability, permeability variation, formation depth, temperature, and net pay, facies changes and reservoir structures as drawn from cores, well logs, and other geological data. Task 2 is reservoir fluid characterization -- determination of physical properties of reservoir fluids including density, viscosity, phase distributions and composition as well as petrogenesis -- source rock identification; and the study of asphaltene precipitation for Alaskan crude oils.

Sharma, G.D.

1991-12-31T23:59:59.000Z

246

Characterization of oil and gas reservoir heterogeneity. Technical progress report, April 1, 1992--June 30, 1992  

SciTech Connect

The ultimate objective of this cooperative research project is to characterize Alaskan petroleum reservoirs in terms of their reserves, physical and chemical properties, geologic configuration in relation to lithofacies and structure, and development potential. The project has two tasks: Task 1 is a geological description of the reservoirs including petrophysical properties, i.e., porosity, permeability, permeability variation, formation depth, temperature, and net pay, facies changes and reservoir structures as drawn from cores, well logs, and other geological data. Task 2 is reservoir fluid characterization-determination of physical properties of reservoir fluids including density, viscosity, phase distributions and composition as well as petrogenesis-source rock identification; and the study of asphaltene precipitation for Alaskan crude oils. Results are discussed.

Sharma, G.D.

1992-10-01T23:59:59.000Z

247

Geologic Distribution of U.S. Proved Reserves, 2009  

U.S. Energy Information Administration (EIA)

Geologic Distribution of U.S. Proved Reserves, 2009 Although proved reserves of crude oil, lease condensate, and natural gas have historically been

248

Magic Reservoir Geothermal Area | Open Energy Information  

Open Energy Info (EERE)

Magic Reservoir Geothermal Area Magic Reservoir Geothermal Area Jump to: navigation, search GEOTHERMAL ENERGYGeothermal Home Geothermal Resource Area: Magic Reservoir Geothermal Area Contents 1 Area Overview 2 History and Infrastructure 3 Regulatory and Environmental Issues 4 Exploration History 5 Well Field Description 6 Geology of the Area 7 Geofluid Geochemistry 8 NEPA-Related Analyses (0) 9 Exploration Activities (0) 10 References Loading map... {"minzoom":false,"mappingservice":"googlemaps3","type":"TERRAIN","zoom":6,"types":["ROADMAP","SATELLITE","HYBRID","TERRAIN"],"geoservice":"google","maxzoom":false,"width":"500px","height":"300px","centre":false,"title":"","label":"","icon":"","visitedicon":"","lines":[],"polygons":[],"circles":[],"rectangles":[],"copycoords":false,"static":false,"wmsoverlay":"","layers":[],"controls":["pan","zoom","type","scale","streetview"],"zoomstyle":"DEFAULT","typestyle":"DEFAULT","autoinfowindows":false,"kml":[],"gkml":[],"fusiontables":[],"resizable":false,"tilt":0,"kmlrezoom":false,"poi":true,"imageoverlays":[],"markercluster":false,"searchmarkers":"","locations":[{"text":"","title":"","link":null,"lat":43.32833333,"lon":-114.3983333,"alt":0,"address":"","icon":"","group":"","inlineLabel":"","visitedicon":""}]}

249

Quantification of Libby Reservoir Water Levels Needed to Maintain or Enhance Reservoir Fisheries, 1983 Final Report.  

DOE Green Energy (OSTI)

The first six months of the fishery investigations in Libby Reservoir were aimed at developing suitable methodology for sampling physical-chemical limnology, fish food availability, fish food habits, and seasonal distribution and abundance of fish populations. Appropriate methods have been developed for all aspects with minor modification of original proposed methodologies. Purse seining has yet to be tested. Physical-chemical limnologic sampling could be reduced or subcontracted with the U.S. Geologic Survey to allow for more intensive sampling of fish food or fish distribution portions of the investigation. Final sample design will be determined during 1983-84. Future directions of the study revolve around two central issues, the potential for flexibility in reservoir operation and determination of how reservoir operation affects fish populations. Simulated maximum drawdown levels during a 40-year period were controlled by power in seven out of eight years. Drawdowns were generally within 10 feet of the flood control rule curve, however. There may be more flexibility with regards to timing of refill and evacuation. This aspect needs to be evaluated further. Production and availability of fish food, suitability of reservoir habitat, and accessibility of off-reservoir spawning and rearing habitat were identified as components of fish ecology which reservoir operation could potentially impact. Two models based on trophic dynamics and habitat suitabilities were suggested as a framework for exploring the relationship of reservoir operation on the fish community.

Shepard, Bradley B.

1984-07-01T23:59:59.000Z

250

Status of Norris Reservoir  

DOE Green Energy (OSTI)

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.

Not Available

1990-09-01T23:59:59.000Z

251

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

SciTech Connect

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

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

2002-10-30T23:59:59.000Z

252

Z .Chemical Geology 145 1998 153159 z /Geochemical Earth Reference Model GERM  

E-Print Network (OSTI)

Z .Chemical Geology 145 1998 153­159 z /Geochemical Earth Reference Model GERM : description on a chemical characterization of the Earth, its major reservoirs, and the fluxes between them. The Z .GERM chemical Z . Z .reservoirs of the present-day Earth, from core to atmosphere; 2 present-day fluxes between

Mcdonough, William F.

253

Structural geology of wells of opportunity tested during 1980 and 1981  

DOE Green Energy (OSTI)

Six geopressured-geothermal reservoirs have been tested. These reservoirs have been isolated in one or more directions by down-to-the-coast growth-type faulting. The two main types are those bounded updip by a single sealing fault and anticlinal traps bounded both up and down dip of the structure. Additional permeability barriers were encountered during testing. These barriers were not predicted in the original geologic evaluations and show the need to seek larger reservoirs in future tests.

Peterson, K.P.

1981-01-01T23:59:59.000Z

254

U.S. Weekly Natural Gas Storage Data  

U.S. Energy Information Administration (EIA)

... Production and Net Imports Natural Gas Storage Storage Reservoirs by Type Underground Natural Gas Storage Facilities in the ... (written copies ...

255

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

Science Conference Proceedings (OSTI)

Advanced reservoir characterization techniques are being used at the Nash Draw Brushy Canyon Pool project to develop reservoir management strategies for optimizing oil recovery from this Delaware reservoir. The reservoir characterization, geologic 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.

Murphy, M.B.

1999-02-01T23:59:59.000Z

256

Lithology and alteration mineralogy of reservoir rocks at Coso Geothermal  

Open Energy Info (EERE)

Lithology and alteration mineralogy of reservoir rocks at Coso Geothermal Lithology and alteration mineralogy of reservoir rocks at Coso Geothermal Area, California Jump to: navigation, search GEOTHERMAL ENERGYGeothermal Home Journal Article: Lithology and alteration mineralogy of reservoir rocks at Coso Geothermal Area, California Details Activities (1) Areas (1) Regions (0) Abstract: Coso is one of several high-temperature geothermal systems associated with recent volcanic activity in the Basin and Range province. Chemical and fluid inclusion data demonstrate that production is from a narrow, asymmetric plume of thermal water that originates from a deep reservoir to the south and then flows laterally to the north. Geologic controls on the geometry of the upwelling plume were investigated using petrographic and analytical analyses of reservoir rock and vein material.

257

Opportunities to improve oil productivity in unstructured deltaic reservoirs  

SciTech Connect

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.

Not Available

1991-01-01T23:59:59.000Z

258

Technical feasibility of chemical flooding in California reservoirs  

SciTech Connect

A study of the applicability of chemical flooding to California is presented. It is shown that the five processes reviewed (CO/sub 2/), micellar-polymer, polymer, caustic and hydrocarbon miscible can increase oil recovery from California reservoirs. Over one half of the 435 California reservoirs on which DOE has crude oil data contain oils with quantities of 25/degree/API or higher and viscosities of less than 20 cp. These reservoirs include sands in the large Wilmington, Belridge, Coalinga, Ventura and Midway Sunset fields. Based on crude oil properties, these reservoirs are candidates for all of the chemical flooding processes (Miscible and non-miscible. Economic success will depend on how well the problems of reservoir geology, CO/sub 2/ availability and mobility control, and surfactant and polymer quality are handled in the design and operation of each project. 40 refs.

Holm, L.W.

1982-01-01T23:59:59.000Z

259

Method of extracting heat from dry geothermal reservoirs  

DOE Patents (OSTI)

Hydraulic fracturing is used to interconnect two or more holes that penetrate a previously dry geothermal reservoir, and to produce within the reservoir a sufficiently large heat-transfer surface so that heat can be extracted from the reservoir at a usefully high rate by a fluid entering it through one hole and leaving it through another. Introduction of a fluid into the reservoir to remove heat from it and establishment of natural (unpumped) convective circulation through the reservoir to accomplish continuous heat removal are important and novel features of the method. (auth)

Potter, R.M.; Robinson, E.S.; Smith, M.C.

1974-01-22T23:59:59.000Z

260

Natural and industrial analogues for release of CO2 from storage reservoirs: Identification of features, events, and processes and lessons learned  

E-Print Network (OSTI)

COMPOSITION OF FLUE GAS STREAMS AND CO 2 SEPARATION 43 3.3. NATURALcompositions by volume of flue (and fuel) gases from selected coal, fuel oil, natural

Lewicki, Jennifer L.; Birkholzer, Jens; Tsang, Chin-Fu

2006-01-01T23:59:59.000Z

Note: This page contains sample records for the topic "natural geological reservoir" from the National Library of EnergyBeta (NLEBeta).
While these samples are representative of the content of NLEBeta,
they are not comprehensive nor are they the most current set.
We encourage you to perform a real-time search of NLEBeta
to obtain the most current and comprehensive results.


261

Use of XML and Java for collaborative petroleum reservoir modeling on the Internet  

Science Conference Proceedings (OSTI)

The GEMINI (Geo-Engineering Modeling through INternet Informatics) is a public-domain, web-based freeware that is made up of an integrated suite of 14 Java-based software tools to accomplish on-line, real-time geologic and engineering reservoir modeling. ... Keywords: GEMINI, Java, Petroleum web-based software, Reservoir modeling, Web start, XML

John Victorine; W. Lynn Watney; Saibal Bhattacharya

2005-11-01T23:59:59.000Z

262

Data Integration for the Generation of High Resolution Reservoir Models  

SciTech Connect

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.

Albert Reynolds; Dean Oliver; Gaoming Li; Yong Zhao; Chaohui Che; Kai Zhang; Yannong Dong; Chinedu Abgalaka; Mei Han

2009-01-07T23:59:59.000Z

263

Utah Associated-Dissolved Natural Gas, Wet After Lease Separation...  

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

Reservoir Discoveries in Old Fields (Billion Cubic Feet) Utah Associated-Dissolved Natural Gas, Wet After Lease Separation, New Reservoir Discoveries in Old Fields (Billion Cubic...

264

Utah Associated-Dissolved Natural Gas, Reserves in Nonproducing...  

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

Reserves in Nonproducing Reservoirs, Wet (Billion Cubic Feet) Utah Associated-Dissolved Natural Gas, Reserves in Nonproducing Reservoirs, Wet (Billion Cubic Feet) Decade Year-0...

265

Utah Natural Gas Wet After Lease Separation, Reserves in Nonproducing...  

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

Wet After Lease Separation, Reserves in Nonproducing Reservoirs (Billion Cubic Feet) Utah Natural Gas Wet After Lease Separation, Reserves in Nonproducing Reservoirs (Billion Cubic...

266

Utah Nonassociated Natural Gas, Wet After Lease Separation, New...  

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

Reservoir Discoveries in Old Fields (Billion Cubic Feet) Utah Nonassociated Natural Gas, Wet After Lease Separation, New Reservoir Discoveries in Old Fields (Billion Cubic Feet)...

267

Utah Natural Gas Liquids Lease Condensate, Reserves in Nonproducing...  

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

in Nonproducing Reservoirs (Million Barrels) Utah Natural Gas Liquids Lease Condensate, Reserves in Nonproducing Reservoirs (Million Barrels) Decade Year-0 Year-1 Year-2 Year-3...

268

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

Science Conference Proceedings (OSTI)

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.

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

2002-02-28T23:59:59.000Z

269

Parallel, high-resolution carbon and sulfur isotope records of the evolving Paleozoic marine sulfur reservoir  

E-Print Network (OSTI)

. Carbonate rocks record the inorganic carbon isotope composition of the oceanic reservoir through geologicalParallel, high-resolution carbon and sulfur isotope records of the evolving Paleozoic marine sulfur, University of California-Riverside, Riverside California 92521-0423, USA b Department of Geological Sciences

Saltzman, Matthew R.

270

Status of Wheeler Reservoir  

DOE Green Energy (OSTI)

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.

Not Available

1990-09-01T23:59:59.000Z

271

Status of Cherokee Reservoir  

DOE Green Energy (OSTI)

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.

Not Available

1990-08-01T23:59:59.000Z

272

Natural and industrial analogues for release of CO2 from storagereservoirs: Identification of features, events, and processes and lessonslearned  

SciTech Connect

The injection and storage of anthropogenic CO{sub 2} in deep geologic formations is a potentially feasible strategy to reduce CO{sub 2} emissions and atmospheric concentrations. While the purpose of geologic carbon storage is to trap CO{sub 2} underground, CO{sub 2} could migrate away from the storage site into the shallow subsurface and atmosphere if permeable pathways such as well bores or faults are present. Large-magnitude releases of CO{sub 2} have occurred naturally from geologic reservoirs in numerous volcanic, geothermal, and sedimentary basin settings. Carbon dioxide and natural gas have also been released from geologic CO{sub 2} reservoirs and natural gas storage facilities, respectively, due to influences such as well defects and injection/withdrawal processes. These systems serve as natural and industrial analogues for the potential release of CO{sub 2} from geologic storage reservoirs and provide important information about the key features, events, and processes (FEPs) that are associated with releases, as well as the health, safety, and environmental consequences of releases and mitigation efforts that can be applied. We describe a range of natural releases of CO{sub 2} and industrial releases of CO{sub 2} and natural gas in the context of these characteristics. Based on this analysis, several key conclusions can be drawn, and lessons can be learned for geologic carbon storage. First, CO{sub 2} can both accumulate beneath, and be released from, primary and secondary reservoirs with capping units located at a wide range of depths. Both primary and secondary reservoir entrapments for CO{sub 2} should therefore be well characterized at storage sites. Second, many natural releases of CO{sub 2} have been correlated with a specific event that triggered the release, such as magmatic fluid intrusion or seismic activity. The potential for processes that could cause geomechanical damage to sealing cap rocks and trigger the release of CO{sub 2} from a storage reservoir should be evaluated. Third, unsealed fault and fracture zones may act as fast and direct conduits for CO{sub 2} flow from depth to the surface. Risk assessment should therefore emphasize determining the potential for and nature of CO{sub 2} migration along these structures. Fourth, wells that are structurally unsound have the potential to rapidly release large quantities of CO{sub 2} to the atmosphere. Risk assessment should therefore be focused on the potential for both active and abandoned wells at storage sites to transport CO{sub 2} to the surface, particularly at sites with depleted oil or gas reservoirs where wells are abundant. Fifth, the style of CO{sub 2} release at the surface varies widely between and within different leakage sites. In rare circumstances, the release of CO{sub 2} can be a self-enhancing and/or eruptive process; this possibility should be assessed in the case of CO{sub 2} leakage from storage reservoirs. Sixth, the hazard to human health has been small in most cases of large surface releases of CO{sub 2}. This could be due to implementation of public education and CO{sub 2} monitoring programs; these programs should therefore be employed to minimize potential health, safety, and environmental effects associated with CO{sub 2} leakage. Finally, while changes in groundwater chemistry were related to CO{sub 2} leakage due to acidification and interaction with host rocks along flow paths, waters remained potable in most cases. Groundwaters should be monitored for changes that may be associated with storage reservoir leakage.

Lewicki, Jennifer L.; Birkholzer, Jens; Tsang, Chin-Fu

2006-03-03T23:59:59.000Z

273

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

Science Conference Proceedings (OSTI)

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.

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

2006-09-30T23:59:59.000Z

274

GEOLOGY FIELD TRIPS IN THE APPALACHIAN MOUNTAINS  

E-Print Network (OSTI)

-- Exploration for Petroleum and Natural Gas (optional laboratory) 87 -- The Obelisk: Revisited 96 -- References recording past events. Rather than letters and words, rock characteristics such as shape, color, composition of answers to questions about the nature of geological data gathered through the field trips and laboratory

Engelder, Terry

275

Assessment and Forecasting Natural Gas Reserve Appreciation in the Gulf Coast Basin  

SciTech Connect

Reserve appreciation, also called reserve growth, is the increase in the estimated ultimate recovery (the sum of year end reserves and cumulative production) from fields subsequent to discovery from extensions, infield drilling, improved recovery of in-place resources, new pools, and intrapool completions. In recent years, reserve appreciation has become a major component of total U.S. annual natural gas reserve additions. Over the past 15 years, reserve appreciation has accounted for more than 80 percent of all annual natural gas reserve additions in the U.S. lower 48 states (Figure 1). The rise of natural gas reserve appreciation basically came with the judgment that reservoirs were much more geologically complex than generally thought, and they hold substantial quantities of natural gas in conventionally movable states that are not recovered by typical well spacing and vertical completion practices. Considerable evidence indicates that many reservoirs show significant geological variations and compartmentalization, and that uniform spacing, unless very dense, does not efficiently tap and drain a sizable volume of the reservoir (Figure 2). Further, by adding reserves within existing infrastructure and commonly by inexpensive recompletion technology in existing wells, reserve appreciation has become the dominant factor in ample, low-cost natural gas supply. Although there is a wide range in natural gas reserve appreciation potential by play and that potential is a function of drilling and technology applied, current natural gas reserve appreciation studies are gross, averaging wide ranges, disaggregated by broad natural gas provinces, and calculated mainly as a function of time. A much more detailed analysis of natural gas reserve appreciation aimed at assessing long-term sustainability, technological amenability, and economic factors, however, is necessary. The key to such analysis is a disaggregation to the play level. Plays are the geologically homogeneous subdivision of the universe of hydrocarbon pools within a basin. Typically, fields within a play share common hydrocarbon type, reservoir genesis, trapping mechanism, and source. Plays provide the comprehensive reference needed to more efficiently develop reservoirs, to extend field limits, and to better assess opportunities for intrafield exploration and development in mature natural gas provinces. Play disaggregation reveals current production trends and highlights areas for further exploration by identifying and emphasizing areas for potential reserve appreciation.

Kim, E.M.; Fisher, W.L.

1997-10-01T23:59:59.000Z

276

Characterization of oil and gas reservoir heterogeneity. Annual report, November 1, 1990--October 31, 1991  

SciTech Connect

The objective of the cooperative research program is to characterize Alaskan reservoirs in terms of their reserves, physical and chemical properties, geologic configuration and structure, and the development potential. The tasks completed during this period include: (1) geologic reservoir description of Endicott Field; (2) petrographic characterization of core samples taken from selected stratigraphic horizons of the West Sak and Ugnu (Brookian) wells; (3) development of a polydispersed thermodynamic model for predicting asphaltene equilibria and asphaltene precipitation from crude oil-solvent mixtures, and (4) preliminary geologic description of the Milne Point Unit.

Not Available

1991-12-31T23:59:59.000Z

277

A novel geotechnical/geostatistical approach for exploration and production of natural gas from multiple geologic strata. Topical report, October--December 1997  

SciTech Connect

Total gas production from several natural gas wells is described. Water production is also given for the wells. The wells are located in the Big Lime/Ravencliff formations and the Pocahontas coal deposit. Plans for degassing various coal mines were also made and are described. Plans involved recovery of methane from an active mine with power generation, reworking and stimulation of coals in existing conventional gas wells, and storage of methane in an abandoned coal mine.

Brunk, R.G.

1997-12-31T23:59:59.000Z

278

MULTI-ATTRIBUTE SEISMIC/ROCK PHYSICS APPROACH TO CHARACTERIZING FRACTURED RESERVOIRS  

SciTech Connect

This project consists of three key interrelated Phases, each focusing on the central issue of imaging and quantifying fractured reservoirs, through improved integration of the principles of rock physics, geology, and seismic wave propagation. This report summarizes the results of Phase I of the project. The key to successful development of low permeability reservoirs lies in reliably characterizing fractures. Fractures play a crucial role in controlling almost all of the fluid transport in tight reservoirs. Current seismic methods to characterize fractures depend on various anisotropic wave propagation signatures that can arise from aligned fractures. We are pursuing an integrated study that relates to high-resolution seismic images of natural fractures to the rock parameters that control the storage and mobility of fluids. Our goal is to go beyond the current state-of-the art to develop and demonstrate next generation methodologies for detecting and quantitatively characterizing fracture zones using seismic measurements. Our study incorporates 3 key elements: (1) Theoretical rock physics studies of the anisotropic viscoelastic signatures of fractured rocks, including up scaling analysis and rock-fluid interactions to define the factors relating fractures in the lab and in the field. (2) Modeling of optimal seismic attributes, including offset and azimuth dependence of travel time, amplitude, impedance and spectral signatures of anisotropic fractured rocks. We will quantify the information content of combinations of seismic attributes, and the impact of multi-attribute analyses in reducing uncertainty in fracture interpretations. (3) Integration and interpretation of seismic, well log, and laboratory data, incorporating field geologic fracture characterization and the theoretical results of items 1 and 2 above. The focal point for this project is the demonstration of these methodologies in the Marathon Oil Company Yates Field in West Texas.

Gary Mavko

2000-10-01T23:59:59.000Z

279

History match simulation of Serrazzano geothermal reservoir  

DOE Green Energy (OSTI)

The simulator SHAFT79 of Lawrence Berkeley Laboratory has been applied to field-wide distributed parameter simulation of the vapor-dominated geothermal reservoir at Serrazzano, Italy. Using a three-dimensional geologically accurate mesh and detailed flow rate data from 19 producing wells, a period of 15.5 years (from 1959 to 1975) has been simulated. The reservoir model used is based on field measurements of temperatures and pressures, laboratory data for core samples, and available geological and hydrological information. The main parameters determined (adjusted) during development of the simulation are permeabilities and much of the initial conditions. Simulated patterns of pressure decline show semi-quantitative agreement with field observations. The simulation suggests that there is cold water recharge and/or incomplete heat transfer from he rock due to fractures in the margins of the reservoir, and some steam flowing to the main well field originates from deep fractures rather than from boiling in the two-phase zones modeled. Simulation methodology and ambiguity of parameter determination is discussed.

Pruess, K.; Weres, O.; Schroeder, R.; Marconcini, R.; Neri, G.

1980-08-01T23:59:59.000Z

280

Imaging Reservoir Quality: Seismic Signatures of Geologic Processes  

SciTech Connect

Lithofacies successions from diverse depositional environments show distinctive patterns in various rock-physics planes (velocity-porosity, velocity-density and porosity-clay). Four clear examples of decameter-scale lithofacies sequences are documented in this study: (1) Micocene fluvial deposits show an inverted-V pattern indicative of dispersed fabric, (2) a fining-upward sequence of mud-rich deep deposits shows a linear trend associated with laminated sand-clay mixtures, (3) sand-rich deposits show a pattern resulting from the scarcity of mixed lithofacies, and (4) a coarsening-upward sequence shows evidence of both dispersed and horizontally laminated mixed lithofacies, with predominating dispersed mixtures generated by bioturbation. It was observed that carbonate-cemented sandstones are extremely heterogeneous in the project deep-water study area. Those from the base of incisions are usually associated with lower shaliness, lower porosity and higher P-impedance, while from the top of flooding surfaces exhibit higher shaliness, higher porosity and lower P-impedance. One rock physics model that captures the observed impedance-porosity trend is the 'stiff-sand model'. For this model, the high-porosity end-member is unconsolidated sand whose initial porosity is a function of sorting and shaliness, while the low-porosity end-member is solid mineral. These two end points are joined with a Hashin-Shtrikman equation. A systematic variation of quartz:clay ratio from proximal to distal locations was observed in the study area even within a single facies. The quartz:clay ratio changes from [0.5:0.5] to [1:0] along the direction of flow, based on the trends of P-impedance vs. porosity as predicted by the rock model for uncemented sands. The results are in agreement with spill-and-fill sequence stratigraphic model in mini-basin setting. In addition, porosity at the distal location ({approx}25 % to 35%) is higher than the porosity at the proximal location ({approx}20 % to 23%). This trend is explained by a sequence stratigraphic model which predicts progressive increase in sorting by turbidity current along the flow, as well as, quantified by a rock model that heuristically accounts for sorting. The results can be applied to improve quantitative predication of sediment parameters from seismic impedance, away from well locations.

Department of Geophysics

2008-06-30T23:59:59.000Z

Note: This page contains sample records for the topic "natural geological reservoir" from the National Library of EnergyBeta (NLEBeta).
While these samples are representative of the content of NLEBeta,
they are not comprehensive nor are they the most current set.
We encourage you to perform a real-time search of NLEBeta
to obtain the most current and comprehensive results.


281

Reservoir quality studies, Arctic National Wildlife Refuge, Alaska  

Science Conference Proceedings (OSTI)

Reservoir quality studies are part of the reservoir management and resource assessment programs of the U.S. Bureau of Land Management in Alaska. Petrographic analyses have been carried out of samples collected from surface exposures in the Arctic National Wildlife Refuge (ANWR), Alaska, to evaluate surface materials as to their potential reservoir rock qualities in the subsurface. This entails characterization of relevant petrologic-petrophysical properties, integration with regional geological-geophysical relationships, and synthesis in terms of likely diagenetic, structural, and stratigraphic conditions in the subsurface. There is a paucity of relevant data in this region. Inferences must be predicated largely on general principles and known relationships elsewhere. A spectrum of lithologies were studied, representing a substantial portion of the regional stratigraphic column. In a number of cases, particularly among the pre-Brookian samples, the rocks appear to have low reservoir potential, based on their present high degree of diagenetic maturity. There is always the possibility - deemed somewhat unlikely here - of subsurface equivalents with more favorable characteristics, due to different original compositions, textures, and/or geologic histories. Brookian sandstones and conglomerates feature samples with fair-good reservoir characteristics, with prospects of being equally good or better in the subsurface. The samples studied suggest the likelihood of horizons with viable reservoir qualities in the subsurface within the ANWR region.

Mowatt, T.C.; Banet, A. (U.S. Bureau of Land Management, Anchorage, AK (United States))

1991-03-01T23:59:59.000Z

282

Reservoir description breathes new life into an old fireflood  

SciTech Connect

The MOCO T reservoir is a Miocene-age (''Stevens equivalent,'' Monterey Formation) unconsolidated sand reservoir in the Midway-Sunset field, Kern County, California. This reservoir was discovered in 1957 as a deeper pay beneath the Monarch and Webster reservoirs. Due to low prices for heavy oil (14/sup 0/ API), the MOCO T was only partially developed and remained essentially shut-in until initiation of in-situ combustion in 1960. Exploitation of the MOCO T by the combustion process continues today, with cumulative production to date of approximately 14 million bbl of oil. The MOCO T reservoir is approximately 500 ft thick and lies at an average drill depth of 2,100-2,700 ft. Based on modern core data and sand distribution maps, these sands were probably deposited by channelized turbidity currents that flowed southwest to northwest in this area. Detailed recorrelation of wireline logs, stratigraphic zonation, and description of individual zones of the MOCO T reservoir in the context of a channelized turbidite system have led to: (1) determination of probable flow paths, vertically and laterally, between injectors and producers by zone, (2) control for workovers to optimize conformance between injection and production intervals, and (3) identification of previously unrecognized and undeveloped reserves. Integration of this geologic model with an understanding of how the combustion front has advanced through the MOCO T reservoir has led to successful placement of infill wells to produce the reservoir more efficiently and completely.

Hall, B.R.

1988-01-01T23:59:59.000Z

283

Research to understand and predict geopressured reservoir characteristics with confidence  

DOE Green Energy (OSTI)

The Department of Energy's Geopressured Geothermal Program has sponsored a series of geoscience studies to resolve key uncertainties in the performance of geopressured reservoirs. The priority areas for research include improving the ability to predict reservoir size and flow capabilities, understanding the role of oil and gas in reservoir depletion and evaluating mechanisms for reservoir pressure maintenance. Long-term production from the Gladys McCall well has provided the basis for most of the current research efforts. The well was shut-in on October 29, 1987, for pressure recovery after producing over 27 million barrels of brine with associated gas. Geologic investigations are evaluating various mechanisms for pressure maintenance in this reservoir, including recharge from adjacent reservoirs or along growth faults, shale dewatering, and laterally overlapping and connected sandstone layers. Compaction studies using shale and sandstone core samples have provided data on the relationship between rock compression and reservoir pressure decline and the correlation to changes in porosity and permeability. The studies support the use of a porosity-coupled reservoir simulation model which has provided an excellent match to the well's production history. 10 refs., 3 figs.

Stiger, S.G.; Prestwich, S.M.

1988-01-01T23:59:59.000Z

284

Elastic and elastoplastic finite element simulations of injection into porous reservoirs.  

E-Print Network (OSTI)

??Underground gas injection has attracted remarkable attention for natural gas storage and carbon dioxide (CO2) geologic sequestration applications. Injection of natural gas into depleted hydrocarbon (more)

Chamani, Amin

2013-01-01T23:59:59.000Z

285

Geothermal reservoir technology  

DOE Green Energy (OSTI)

A status report on Lawrence Berkeley Laboratory's Reservoir Technology projects under DOE's Hydrothermal Research Subprogram is presented. During FY 1985 significant accomplishments were made in developing and evaluating methods for (1) describing geothermal systems and processes; (2) predicting reservoir changes; (3) mapping faults and fractures; and (4) field data analysis. In addition, LBL assisted DOE in establishing the research needs of the geothermal industry in the area of Reservoir Technology. 15 refs., 5 figs.

Lippmann, M.J.

1985-09-01T23:59:59.000Z

286

Guntong field: Development and management of a multiple-reservoir offshore waterflood  

SciTech Connect

The Guntong field, the largest waterflood field in offshore peninsular Malaysia, with an oil-in-place (OIP) of about 200 million m{sup 3}, has been producing since 1985. The field contains 13 stacked reservoirs with small gas caps and limited aquifer support. This paper describes some of the significant reservoir, geologic, and facility challenges faced during development and management of this complex reservoir system. A combination of five-spot and peripheral waterflood patterns was selected to provide the required areal coverage, and reservoirs were commingled into two operational groups. Key reservoir management strategies to maximize performance include determination of optimum target reservoir pressures, use of a PC-based program to guide production and injection targets, and meeting pattern-balancing and capacity-enhancement programs. The response to the reservoir management efforts has been favorable, with an all-time-high production rate of 14,000 m{sup 3}/d recorded in 1994.

Chik, A.N.; Selamat, S.; Elias, M.R.; White, J.P.; Wakatake, M.T.

1996-12-01T23:59:59.000Z

287

Geology of the Tambaredjo oil field, Suriname  

SciTech Connect

After the initial discovery in the sixties of oil below the coastal plain of Suriname (S. America), the State Oil Company of Suriname started production of the unique Tambaredjo field in 1982. The heavy, biodegraded oil (14-16[degrees] API) is produced under compaction drive, from the Paleocene T-sand (average thickness 5 m) at a depth of about 300 m. More than 300 wells have been drilled in an area of about 200 km[sup 2]. High resolution seismics makes it possible to correlate units down to 2 m thick. This dense network of bore holes is very suitable for geological correlations and 3D modeling. The T-sand reservoir consists of angular, medium to coarse grained unconsolidated sands with interfingering clays and lignites. The sands are deposited on a well cemented erosional Cretaceous basement. The reservoir is sealed by locally continuous clays. The oil is trapped in structural highs created by syn-sedimentary rejuvenated basement faults. The depositional environment of the T-sand ranges from fluviatile to deltaic. Frequent avulsion and synsedimentary faulting created a highly compartmented reservoir. Although interconnectedness of the sand bodies is high, clay smears and silting out of the edges confine reservoir compartments. The best genetic sand units such as channel fills or mouth bar deposits hardly correlate over more than a few hundred meters. The Tambaredjo oil field offers an unique opportunity to study the detailed sedimentology and petroleum geology of a fluvio-deltaic transitional realm on the passive margin along the Guiana coast.

Dronkert, H. (Delft Univ. of Technology (Netherlands)); Wong, T.E. (Geological Survey of the Netherlands, Haarlem (Netherlands))

1993-02-01T23:59:59.000Z

288

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

SciTech Connect

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.

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

2003-06-01T23:59:59.000Z

289

A better understanding of a Uinta Basin channelized analog reservoir through geostatistics and reservoir simulation  

E-Print Network (OSTI)

The Green River Formation is located in the Uinta basin of northeastern Utah. It contains several reservoirs that can be classified as lacustrine such as the Altamont-Bluebell and Red Wash. Lacustrine reservoirs are abundant in other provinces in the world such as China, Southeast Asia, Brazil, West Africa, and the Caspian Sea. Even though they can contain important accumulations of hydrocarbons, our understanding of the primary controls on fluid flow within these systems is still not clear. This ambiguity leads in some cases to inefficient recovery of hydrocarbons in such reservoirs. This study is aimed at clarifying the effects of heterogeneities in channelized reservoirs on fluid flow. It uses a multidisciplinary approach combining geologic knowledge with reservoir engineering. It involves the geologic modeling and fluid flow simulation of a channelized outcrop of the Green River formation. The study of this outcrop provides insights for modeling, understanding, and possibly predicting the behavior of channelized oil and gas reservoirs. Results show that the number of channels in the model can have a significant effect on performance. The rock properties in these channels and the channel paths are also important factors that determine the recovery efficiency. Other findings include the effect on performance of vertical anisotropy in a channelized reservoir. We discovered that an isotropic reservoir performs better than an anisotropic one and that the well perforation interval is extremely important when comparing the performance of several anisotropic cases. Finally, we investigated the effects of the recovery strategy on performance in a channelized setting. We found that waterflooding yields better results than any of the other recovery techniques analyzed. Sensitivity runs with different waterflood patterns indicated that a staggered line drive results in the best performance in the analog channelized reservoir we modeled, as it allows for the best recovery factor in the least amount of time. The results of this work can be used qualitatively to predict performance in a channelized setting but their use is limited quantitatively because of the issue of scale, i.e. the outcrop width is much less than typical interwell scale.

Robbana, Enis

2002-01-01T23:59:59.000Z

290

Geothermal Reservoir Dynamics - TOUGHREACT  

E-Print Network (OSTI)

Swelling in a Fractured Geothermal Reservoir, presented atTHC) Modeling Based on Geothermal Field Data, Geothermics,and Silica Scaling in Geothermal Production-Injection Wells

2005-01-01T23:59:59.000Z

291

Characterization of oil and gas reservoir heterogeneity. [Quarterly technical progress report], April 1, 1993--June 30, 1993  

SciTech Connect

The ultimate objective of this cooperative research project is to characterize Alaskan petroleum reservoirs in terms of their reserves, physical and chemical properties, geologic configuration in relation to lithofacies and structure, and development potential. The project has two tasks: Task I is a geological description of the reservoirs including petrophysical properties, i.e., porosity, permeability, permeability variation, formation depth, temperature, and net pay, facies changes and reservoir structures as drawn from cores, well logs, and other geological data. Task 2 is reservoir fluid characterization--determination of physical properties of reservoir fluids including density, viscosity, phase distributions and composition as well as petrogenesis--source rock identification; and the study of asphaltene precipitation for Alaskan crude oils.

Sharma, G.D.

1993-08-01T23:59:59.000Z

292

Analysis of reservoir performance and forecasting for the eastern area of the C-2 Reservoir, Lake Maracaibo, Venezuela  

E-Print Network (OSTI)

This research developed a numerical simulation based on the latest reservoir description to evaluate the feasibility of new infill wells to maximize the recovery specifically in the eastern region of the reservoir operated by Petroleos de Venezuela S.A. (PDVSA). This research provides a full-field numerical simulation that predicts performance and aids in planning future development with infill wells for a reservoir located at the south of Block V, Lamar in Lake Maracaibo. The simulation is especially promising for the eastern region, which has the current highest oil production behavior. The final model achieved an acceptable history match for pressure and fluids for the entire reservoir, especially for the eastern area. On the basis of this model and an opportunity index, the best six infill wells should be located in the eastern area of the reservoir, which would increased the cumulated production in 44.5 MMSTB. This work is important because it provides the first numerical simulation for the entire reservoir that considers the new geological model developed during reservoir description. Furthermore, it provides PDVSA with a powerful tool for planning and reservoir management decisions, especially in the eastern area of the reservoir. Predictions resulting from this area show an important increment in the final reservoir recovery over the base case, production depletion under current conditions without any change. On the basis of these results, I strongly recommend starting a new infill drilling campaign in the eastern area as indicated by the simulation results to increase the oil rate reservoir productions and to improve total ultimate recovery.

Urdaneta Anez, Jackeline C

2001-01-01T23:59:59.000Z

293

Enhancing Reservoir Management in the Appalach  

NLE Websites -- All DOE Office Websites (Extended Search)

Reservoir Management in the Appalachian Basin by Identifying Technical Reservoir Management in the Appalachian Basin by Identifying Technical Barrier and Preferred Practices Final Report Reporting Period Start Date: September 1, 2001 Reporting Period End Date: September 15, 2003 Principal Author(s): Ronald R. McDowell Khashayar Aminian Katharine L. Avary John M. Bocan Michael Ed. Hohn Douglas G. Patchen September 2003 DE-FC26-01BC15273 West Virginia University Research Corporation West Virginia Geological and Economic Survey (subcontractor) ii DISCLAIMER This report was prepared as an account of work sponsored by an agency of the United States Government. Neither the United States Government nor any agency thereof, nor any of their employees, makes any warranty, express or implied, or assumes any legal liability or responsibility for the accuracy, completeness, or usefulness of any information, apparatus,

294

Physical processes of subsidence in geothermal reservoirs  

DOE Green Energy (OSTI)

The objectives of this project were to acquire core and fluid from producing geothermal reservoirs (East Mesa, United States, and Cerro Prieto, Mexico); to test specimens of this core for their short-term and long-term (creep) compaction response; and to develop a compaction constitutive model that would allow future analysis of reservoir compaction and a surface subsidence. A total of approximately two hundred feet of core was obtained from eleven wells in the two geothermal fields. Depths and porosities ranged from 3500 to 11,000 feet and 15 to 40 percent, respectively. Several samples of geothermal fluids were also obtained. After geologically and geochemically describing the materials obtained, selected specimens were tested for their response to the pressures and temperatures of the geothermal environment and to simulated changes in those conditions that would be caused by production. Short-term tests (for example, tests for compressibility extending over a time interval of an hour or less in the laboratory) indicated that these sedimentary materials behaved normally with respect to the expected behavior of reservoir sandstones of these depths and porosities. Compressibilities were of the order 1 x 10/sup 6/ psi. Long-term tests, extending up to several weeks in duration, indicated that pore pressure reduction, simulating reservoir production, tended to cause creep compaction at an initial rate of about 1 x 10/sup -7/ percent porosity reduction per second.

Schatz, J.F.

1982-06-01T23:59:59.000Z

295

Detection of CO2 Seepage From Geological Sequestration Sites Using an Array of Downhole Pressure Gauges Jalal Jalali, Shahab D. Mohaghegh, Dept. of Petroleum & Natural Gas Engineering, West Virginia University  

E-Print Network (OSTI)

especially in smart fields because of their improved reliability and valuable information they provide?50?1 grid system. Some of the reservoir properties are shown on Table 1. )()(2 iTi i XXXXD --= Figure 4 prediction 4 days after seepage occurred in the reservoir. Figure 2 shows the architecture of the ANN (Back

Mohaghegh, Shahab

296

Exploration model for possible geothermal reservoir, Coso Hot Springs KGRA,  

Open Energy Info (EERE)

model for possible geothermal reservoir, Coso Hot Springs KGRA, model for possible geothermal reservoir, Coso Hot Springs KGRA, Inyo Co. , California Jump to: navigation, search GEOTHERMAL ENERGYGeothermal Home Conference Proceedings: Exploration model for possible geothermal reservoir, Coso Hot Springs KGRA, Inyo Co. , California Details Activities (1) Areas (1) Regions (0) Abstract: The purpose of this study was to test the hypothesis that a steam-filled fracture geothermal reservoir exists at Coso Hot Springs KGRA, as proposed by Combs and Jarzabek (1977). Gravity data collected by the USGS (Isherwood and Plouff, 1978) was plotted and compared with the geology of the area, which is well known. An east-west trending Bouguer gravity profile was constructed through the center of the heat flow anomaly described by Combs (1976). The best fit model for the observed gravity at

297

Improved Upscaling & Well Placement Strategies for Tight Gas Reservoir Simulation and Management  

E-Print Network (OSTI)

Tight gas reservoirs provide almost one quarter of the current U.S. domestic gas production, with significant projected increases in the next several decades in both the U.S. and abroad. These reservoirs constitute an important play type, with opportunities for improved reservoir simulation & management, such as simulation model design, well placement. Our work develops robust and efficient strategies for improved tight gas reservoir simulation and management. Reservoir simulation models are usually acquired by upscaling the detailed 3D geologic models. Earlier studies of flow simulation have developed layer-based coarse reservoir simulation models, from the more detailed 3D geologic models. However, the layer-based approach cannot capture the essential sand and flow. We introduce and utilize the diffusive time of flight to understand the pressure continuity within the fluvial sands, and develop novel adaptive reservoir simulation grids to preserve the continuity of the reservoir sands. Combined with the high resolution transmissibility based upscaling of flow properties, and well index based upscaling of the well connections, we can build accurate simulation models with at least one order magnitude simulation speed up, but the predicted recoveries are almost indistinguishable from those of the geologic models. General practice of well placement usually requires reservoir simulation to predict the dynamic reservoir response. Numerous well placement scenarios require many reservoir simulation runs, which may have significant CPU demands. We propose a novel simulation-free screening approach to generate a quality map, based on a combination of static and dynamic reservoir properties. The geologic uncertainty is taken into consideration through an uncertainty map form the spatial connectivity analysis and variograms. Combining the quality map and uncertainty map, good infill well locations and drilling sequence can be determined for improved reservoir management. We apply this workflow to design the infill well drilling sequence and explore the impact of subsurface also, for a large-scale tight gas reservoir. Also, we evaluated an improved pressure approximation method, through the comparison with the leading order high frequency term of the asymptotic solution. The proposed pressure solution can better predict the heterogeneous reservoir depletion behavior, thus provide good opportunities for tight gas reservoir management.

Zhou, Yijie

2013-08-01T23:59:59.000Z

298

REMOTE SENSING GEOLOGICAL SURVEY  

E-Print Network (OSTI)

REMOTE SENSING IN GEOLOGICAL SURVEY OF BRAZIL August/2010 Mônica Mazzini Perrotta Remote Sensing Division Head #12;SUMMARY The Geological Survey of Brazil mission The Remote Sensing Division Main remote, Paleontology, Remote Sensing Director of Hydrology and Land Management But Remote Sensing Division gives

299

GEOLOGY AND HYDROTHERMAL ALTERATION OF THE RAFT RIVER GEOTHERMAL SYSTEM,  

Open Energy Info (EERE)

GEOLOGY AND HYDROTHERMAL ALTERATION OF THE RAFT RIVER GEOTHERMAL SYSTEM, GEOLOGY AND HYDROTHERMAL ALTERATION OF THE RAFT RIVER GEOTHERMAL SYSTEM, IDAHO Jump to: navigation, search GEOTHERMAL ENERGYGeothermal Home Conference Proceedings: GEOLOGY AND HYDROTHERMAL ALTERATION OF THE RAFT RIVER GEOTHERMAL SYSTEM, IDAHO Details Activities (3) Areas (1) Regions (0) Abstract: The Raft River geothermal system is located in southern Idaho, near the Utah-Idaho state boarder in the Raft River Valley. The field, which is owned and operated by U.S. Geothermal, has been selected as an EGS demonstration site by the U. S. Department of Energy. This paper summarizes ongoing geologic and petrologic investigations being conducted in support of this project. The reservoir is developed in fractured Proterozoic schist and quartzite, and Archean quartz monzonite cut by younger diabase

300

Microsoft Word - CCS Geologic Storage-Intro_2011l.docx  

NLE Websites -- All DOE Office Websites (Extended Search)

Geologic Storage Geologic Storage Geologic carbon sequestration involves the storage of carbon dioxide (CO 2 ) in deep underground geologic formations. The majority of geologic formations considered for CO 2 storage, deep saline or depleted oil and gas reservoirs, are layers of subsurface porous rock that are overlain by a layer or multiple layers of low-permeability rock. Under high pressures, CO 2 is a supercritical fluid, with the high- density characteristics of a liquid but behaves like a gas by filling all available volume. Coal seams are also a viable option for geologic storage. When CO 2 is injected into a coal formation it is adsorbed onto the coal surfaces and methane gas is released and produced in adjacent wells. NETL's Core R&D research is focused on developing the ability to characterize a geologic formation

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they are not comprehensive nor are they the most current set.
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to obtain the most current and comprehensive results.


301

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

Science Conference Proceedings (OSTI)

The objective of this project is 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. Project objectives are divided into two major phases. The objectives of the reservoir characterization phase of the project are to provide a detailed understanding of the architecture and heterogeneity of two fields, the Ford Geraldine unit and Ford West field, which produce from the Bell Canyon and Cherry Canyon Formations, respectively, of the Delaware Mountain Group and to compare Bell Canyon and Cherry Canyon reservoirs. Reservoir characterization will utilize 3-D seismic data, high-resolution sequence stratigraphy, subsurface field studies, outcrop characterization, and other techniques. Once the reservoir- characterization study of both fields is completed, a pilot area of approximately 1 mi{sup 2} in one of the fields will be chosen for reservoir simulation. The objectives of the implementation phase of the project are to (1) apply the knowledge gained from reservoir characterization and simulation studies to increase recovery from the pilot area, (2) demonstrate that economically significant unrecovered oil remains in geologically resolvable untapped compartments, and (3) test the accuracy of reservoir characterization and flow simulation as predictive tools in resource preservation of mature fields. A geologically designed, enhanced-recovery program (CO{sub 2} flood, water flood, or polymer flood) and well-completion program will be developed, and one to three infill wells will be drilled and cored. Through technology transfer workshops and other present at ions, the knowledge gained in the comparative study of these two fields can then be applied to increase product ion from the more than 100 other Delaware Mountain Group reservoirs.

Dutton, S.P.

1997-10-30T23:59:59.000Z

302

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

SciTech Connect

The objective of this project is 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. Project objectives are divided into two major phases. The objectives of the reservoir characterization phase of the project are to provide a detailed understanding of the architecture and heterogeneity of two fields, the Ford Geraldine unit and Ford West field, which produce from the Bell Canyon and Cherry Canyon Formations, respectively, of the Delaware Mountain Group and to compare Bell Canyon and Cherry Canyon reservoirs. Reservoir characterization will utilize 3-D seismic data, high-resolution sequence stratigraphy, subsurface field studies, outcrop characterization, and other techniques. Once the reservoir-characterization study of both fields is completed, a pilot area of approximately 1 mi 2 in one of the fields will be chosen for reservoir simulation. The objectives of the implementation phase of the project are to (1) apply the knowledge gained from reservoir characterization and simulation studies to increase recovery from the pilot area, (2) demonstrate that economically significant unrecovered oil remains in geologically resolvable untapped compartments, and (3) test the accuracy of reservoir characterization and flow simulation as predictive tools in resource preservation of mature fields. A geologically designed, enhanced-recovery program (CO 2 flood, waterflood, or polymer flood) and well-completion program will be developed, and one to three infill wells will be drilled and cored. Through technology transfer workshops and other presentations, the knowledge gained in the comparative study of these two fields can then be applied to increase production from the more than 100 other Delaware Mountain Group reservoirs.

Shirley P. Dutton

1997-04-30T23:59:59.000Z

303

Application of advanced reservoir characterization, simulation, and production optimization strategies to maximize recovery in slope and basin clastic reservoirs, West Texas (Delaware Basin). Technical progress report  

SciTech Connect

The objective of this project is 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. Project objectives are divided into two major phases. The objectives of the reservoir characterization phase of the project are to provide a detailed understanding of the architecture and heterogeneity of two fields, the Ford Geraldine unit and Ford West field, which produce from the Bell Canyon and Cherry Canyon Formations, respectively, of the Delaware Mountain Group and to compare Bell Canyon and Cherry Canyon reservoirs. Reservoir characterization will utilize 3-D seismic data, high-resolution sequence stratigraphy, subsurface field studies, outcrop characterization, and other techniques. One the reservoir-characterization study of both field is completed, a pilot area of approximately 1 mi{sup 2} in one of the fields will be chosen for reservoir simulation. The objectives of the implementation phase of the project are to: (1) apply the knowledge gained from reservoir characterization and simulation studies to increase recovery from the pilot area; (2) demonstrate that economically significant unrecovered oil remains in geologically resolvable untapped compartments; and (3) test the accuracy of reservoir characterization and flow simulation as predictive tools in resource preservation of mature fields. A geologically designed, enhanced recovery program (CO{sub 2} flood, waterflood, or polymer flood) and well-completion program will be developed, and one to three infill well will be drilled and cored. Technical progress is summarized for: geophysical characterization; reservoir characterization; outcrop characterization; and producibility problem characterization.

Dutton, S.P.

1996-04-30T23:59:59.000Z

304

Analysis of the Development of Messoyakha Gas Field: A Commercial Gas Hydrate Reservoir  

E-Print Network (OSTI)

Natural gas is an important energy source that contributes up to 25% of the total US energy reserves (DOE 2011). An increase in natural gas demand spurs further development of unconventional resources, including methane hydrate (Rajnauth 2012). Natural gas from methane hydrate has the potential to play a major role in ensuring adequate future energy supplies in the US. The worldwide volume of gas in the hydrate state has been estimated to be approximately 1.5 x 10^16 m^3 (Makogon 1984). More than 230 gas-hydrate deposits have been discovered globally. Several production technologies have been tested; however, the development of the Messoyakha field in the west Siberian basin is the only successful commercial gas-hydrate field to date. Although the presence of gas hydrates in the Messoyakha field was not a certainty, this current study determined the undeniable presence of gas hydrates in the reservoir. This study uses four models of the Messoyakha field structure and reservoir conditions and examines them based on the available geologic and engineering data. CMG STARS and IMEX software packages were used to calculate gas production from a hydrate-bearing formation on a field scale. Results of this analysis confirm the presence of gas hydrates in the Messoyakha field and also determine the volume of hydrates in place. The cumulative production from the field on January 1, 2012 is 12.9 x 10^9 m^3, and it was determined in this study that 5.4 x 10^9 m^3 was obtained from hydrates. The important issue of pressure-support mechanisms in developing a gas hydrate reservoir was also addressed in this study. Pressure-support mechanisms were investigated using different evaluation methods such as the use of gas-injection well patterns and gas/water injection using isothermal and non-isothermal simulators. Several aquifer models were examined. Simulation results showed that pressure support due to aquifer activity was not possible. Furthermore, it was shown that the water obtained from hydrates was not produced and remained in the reservoir. Results obtained from the aquifer models were confirmed by the actual water production from the field. It was shown that water from hydrates is a very strong pressure-support mechanism. Water not only remained in the reservoir, but it formed a thick water-saturated layer between the free-gas and gas-hydrate zone. Finally, thermodynamic behavior of gas hydrate decomposition was studied. Possible areas of hydrate preservation were determined. It was shown that the central top portion of the field preserved most of hydrates due to temperature reduction of hydrate decomposition.

Omelchenko, Roman 1987-

2012-12-01T23:59:59.000Z

305

International Symposium on Site Characterization for CO2 Geological Storage  

E-Print Network (OSTI)

the century-long history of oil and gas ex- ploration andare in areas that have a history of oil, natural gas, and/orGULF COAST OIL RESERVOIRS 1. Production History. The Wellman

Tsang, Chin-Fu

2006-01-01T23:59:59.000Z

306

Improved recovery from Gulf of Mexico reservoirs. Quarterly status report, January 1--March 31, 1996  

Science Conference Proceedings (OSTI)

On February 18, 1992, Louisiana State University with two technical subcontractors, BDM, Inc. and ICF, Inc., began a research program to estimate the potential oil and gas reserve additions that could result from the application of advanced secondary and enhanced oil recovery technologies and the exploitation of undeveloped and attic oil zones in the Gulf of Mexico oil fields that are related to piercement salt domes. This project is a one year continuation of this research and will continue work in reservoir description, extraction processes, and technology transfer. Detailed data will be collected for two previously studies reservoirs: a South Marsh Island reservoir operated by Taylor Energy and one additional Gulf of Mexico reservoir operated by Mobil. Additional reservoirs identified during the project will also be studied if possible. Data collected will include 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 will be used to refine reservoir and geologic characterization of these reservoirs. Further laboratory investigation will provide additional simulation input data in the form of PVT properties, relative permeabilities, capillary pressure, and water compatibility. Geological investigations will be conducted to refine the models of mud-rich submarine fan architectures used by seismic analysts and reservoir engineers. Research on advanced reservoir simulation will also be conducted. This report describes a review of fine-grained submarine fans and turbidite systems.

Kimbrell, W.C.; Bassiouni, Z.A.; Bourgoyne, A.T.

1996-04-30T23:59:59.000Z

307

dry natural gas production - U.S. Energy Information ...  

U.S. Energy Information Administration (EIA)

Dry natural gas production: The process of producing consumer-grade natural gas. Natural gas withdrawn from reservoirs is reduced by volumes used at the production ...

308

Case studies of the application of the Certification Framework to two geologic carbon sequestration sites  

E-Print Network (OSTI)

leg of the Fulshear natural gas storage reservoir southeastThe natural gas of the Fulshear gas storage facility will beCO 2 storage region, the impact of CO 2 on the natural gas

Oldenburg, Curtis M.

2009-01-01T23:59:59.000Z

309

Fractured shale reservoirs: Towards a realistic model  

Science Conference Proceedings (OSTI)

Fractured shale reservoirs are fundamentally unconventional, which is to say that their behavior is qualitatively different from reservoirs characterized by intergranular pore space. Attempts to analyze fractured shale reservoirs are essentially misleading. Reliance on such models can have only negative results for fractured shale oil and gas exploration and development. A realistic model of fractured shale reservoirs begins with the history of the shale as a hydrocarbon source rock. Minimum levels of both kerogen concentration and thermal maturity are required for effective hydrocarbon generation. Hydrocarbon generation results in overpressuring of the shale. At some critical level of repressuring, the shale fractures in the ambient stress field. This primary natural fracture system is fundamental to the future behavior of the fractured shale gas reservoir. The fractures facilitate primary migration of oil and gas out of the shale and into the basin. In this process, all connate water is expelled, leaving the fractured shale oil-wet and saturated with oil and gas. What fluids are eventually produced from the fractured shale depends on the consequent structural and geochemical history. As long as the shale remains hot, oil production may be obtained. (e.g. Bakken Shale, Green River Shale). If the shale is significantly cooled, mainly gas will be produced (e.g. Antrim Shale, Ohio Shale, New Albany Shale). Where secondary natural fracture systems are developed and connect the shale to aquifers or to surface recharge, the fractured shale will also produce water (e.g. Antrim Shale, Indiana New Albany Shale).

Hamilton-Smith, T. [Applied Earth Science, Lexington, KY (United States)

1996-09-01T23:59:59.000Z

310

Geologic CO2 Sequestration and Subsurface Property Rights: A Legal and Economic Analysis  

E-Print Network (OSTI)

....................................... 46 2.5.1 Natural Gas Storage reservoirs have been used for storing natural gas imported by pipeline, and make up about 85% of gas storage capacity in America.41 The technology for natural gas storage in depleted reservoirs is well

311

Reservoir description is key to steamflood planning and implementation, Webster Reservoir, Midway-Sunset Field, Kern County, California  

SciTech Connect

The Webster reservoir at Midway-Sunset field, Kern County, California, is an unconsolidated sand reservoir of Miocene age (''Stevens equivalent,'' Monterey Formation). The Webster was discovered in 1910 but, due to poor heavy oil (14/sup 0/ API) economics, development for primary production and subsequent enhanced recovery were sporadic. Currently, the reservoir produces by cyclic steam stimulation in approximately 35 wells. Cumulative oil production for the Webster since 1910 is about 13 million bbl. The Webster is subdivided into two reservoirs - the Webster Intermediate and Webster Main. The Webster Intermediate directly overlies the Webster Main in one area but it is separated by up to 300 ft of shale elsewhere. The combined thickness of both Webster reservoirs averages 250 ft and is located at a drilling depth of 1,100-1,800 ft. From evaluation of modern core data and sand distribution maps, the Webster sands are interpreted to have been deposited by turbidity currents that flowed from southwest to northeast in this area. Oil is trapped in the Webster reservoir where these turbidites were subsequently folded on a northwest-southeast-trending anticline. Detailed recorrelation on wireline logs, stratigraphic zonation, detailed reservoir description by zone, and sedimentary facies identification in modern cores has led to development of a geologic model for the Webster. This model indicates that the Webster Intermediate was deposited predominately by strongly channelized turbidity currents, resulting in channel-fill sands, and that the Webster Main was deposited by less restricted flows, resulting in more lobate deposits.

Hall, B.R.; Link, M.H.

1988-01-01T23:59:59.000Z

312

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

Science Conference Proceedings (OSTI)

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.

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

1998-04-22T23:59:59.000Z

313

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

Science Conference Proceedings (OSTI)

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.

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

1998-01-26T23:59:59.000Z

314

Reservoir characterization of Pennsylvanian sandstone reservoirs. Final report  

SciTech Connect

This final report summarizes the progress during the three years of a project on Reservoir Characterization of Pennsylvanian Sandstone Reservoirs. The report is divided into three sections: (i) reservoir description; (ii) scale-up procedures; (iii) outcrop investigation. The first section describes the methods by which a reservoir can be described in three dimensions. The next step in reservoir description is to scale up reservoir properties for flow simulation. The second section addresses the issue of scale-up of reservoir properties once the spatial descriptions of properties are created. The last section describes the investigation of an outcrop.

Kelkar, M.

1995-02-01T23:59:59.000Z

315

Improved recovery from Gulf of Mexico reservoirs  

Science Conference Proceedings (OSTI)

The Gulf of Mexico Basin offers the greatest near-term potential for reducing the future decline in domestic oil and gas production. The Basin is less mature than productive on-shore areas, large unexplored areas remain, and there is great potential for reducing bypassed oil in known fields. Much of the remaining oil in the offshore is trapped in formations that are extremely complex due to intrusions Of salt domes. Recently, however, 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. On February 18, 1992, Louisiana State University (the Prime Contractor) with two technical subcontractors, BDNL Inc. and ICF, Inc., began a research program to estimate the potential oil and gas reserve additions that could result from the application of advanced secondary and enhanced oil recovery technologies and the exploitation of undeveloped and attic oil zones in the Gulf of Mexico oil fields that are related to piercement salt dornes. This project is a one year continuation of this research and will continue work in reservoir description, extraction processes, and technology transfer. Detailed data will be collected for two previously studied reservoirs: a South Marsh Island reservoir operated by Taylor Energy and a South Pelto reservoir operated by Mobil. This data will include 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. Geologic data is being compiled; extraction research has not begun.

Schenewerk, P.

1995-07-30T23:59:59.000Z

316

Geological, Geophysical, And Thermal Characteristics Of The Salton Sea Geothermal Field, California  

DOE Green Energy (OSTI)

The Salton Sea Geothermal Field is the largest water-dominated geothermal field in the Salton Trough in Southern California. Within the trough, local zones of extension among active right-stepping right-lateral strike-slip faults allow mantle-derived magmas to intrude the sedimentary sequence. The intrusions serves as heat sources to drive hydrothermal systems. We can characterize the field in detail because we have an extensive geological and geophysical data base. The sediments are relatively undeformed and can be divided into three categories as a function of depth: (1) low-permeability cap rock, (2) upper reservoir rocks consisting of sandstones, siltstones, and shales that were subject to minor alterations, and (3) lower reservoir rocks that were extensively altered. Because of the alteration, intergranular porosity and permeability are reduced with depth. permeability is enhanced by renewable fractures, i.e., fractures that can be reactivated by faulting or natural hydraulic fracturing subsequent to being sealed by mineral deposition. In the central portion of the field, temperature gradients are high near the surface and lower below 700 m. Surface gradients in this elliptically shaped region are fairly constant and define a thermal cap, which does not necessarily correspond to the lithologic cap. At the margin of the field, a narrow transition region, with a low near-surface gradient and an increasing gradient at greater depths, separates the high temperature resource from areas of normal regional gradient. Geophysical and geochemical evidence suggest that vertical convective motion in the reservoir beneath the thermal cap is confined to small units, and small-scale convection is superimposed on large-scale lateral flow of pore fluid. Interpretation of magnetic, resistivity, and gravity anomalies help to establish the relationship between the inferred heat source, the hydrothermal system, and the observed alteration patterns. A simple hydrothermal model is supported by interpreting the combined geological, geophysical, and thermal data. In the model, heat is transferred from an area of intrusion by lateral spreading of hot water in a reservoir beneath an impermeable cap rock.

Younker, L.W.; Kasameyer, P. W.; Tewhey, J. D.

1981-01-01T23:59:59.000Z

317

Natural  

Gasoline and Diesel Fuel Update (EIA)

Summary of U.S. Natural Gas Imports and Exports, 1992-1996 Table 1992 1993 1994 1995 1996 Imports Volume (million cubic feet) Pipeline Canada............................. 2,094,387 2,266,751 2,566,049 2,816,408 2,883,277 Mexico .............................. 0 1,678 7,013 6,722 13,862 Total Pipeline Imports....... 2,094,387 2,268,429 2,573,061 2,823,130 2,897,138 LNG Algeria .............................. 43,116 81,685 50,778 17,918 35,325 United Arab Emirates ....... 0 0 0 0 4,949 Total LNG Imports............. 43,116 81,685 50,778 17,918 40,274 Total Imports......................... 2,137,504 2,350,115 2,623,839 2,841,048 2,937,413 Average Price (dollars per thousand cubic feet) Pipeline Canada............................. 1.84 2.02 1.86 1.48 1.96 Mexico .............................. - 1.94 1.99 1.53 2.25 Total Pipeline Imports.......

318

Integration of advanced geoscience and engineering techniques to quantify interwell heterogeneity in reservoir models. First annual report, September 29, 1993--September 30, 1994  

Science Conference Proceedings (OSTI)

The goal of this project is to provide a more quantitative definition of reservoir heterogeneity. This objective will be accomplished through the integration of geologic, geophysical, and engineering databases into a multidisciplinary understanding of reservoir architecture and associated fluid-rock and fluid-fluid interactions. The intent is to obtain a quantitative reservoir description incorporating outcrop, field, well-to-well, and laboratory core and fluid data of widely varying scales. This interdisciplinary effort will integrate 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. A more accurate reservoir description will allow 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, is available for the field research activities that will be conducted.

Martin, F.D.; Buckley, J.S.; Weiss, W.W.; Ouenes, A.

1995-05-01T23:59:59.000Z

319

Reservoir Protection (Oklahoma)  

Energy.gov (U.S. Department of Energy (DOE))

The Oklahoma Water Resource Board has the authority to make rules for the control of sanitation on all property located within any reservoir or drainage basin. The Board works with the Department...

320

Enhanced oil recovery through water imbibition in fractured reservoirs using Nuclear Magnetic Resonance.  

E-Print Network (OSTI)

??Conventional waterflooding methods of oil recovery are difficult to apply when reservoirs show evidence of natural fractures, because injected water advances through paths of high (more)

Hervas Ordonez, Rafael Alejandro

2012-01-01T23:59:59.000Z

Note: This page contains sample records for the topic "natural geological reservoir" from the National Library of EnergyBeta (NLEBeta).
While these samples are representative of the content of NLEBeta,
they are not comprehensive nor are they the most current set.
We encourage you to perform a real-time search of NLEBeta
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321

Session: Reservoir Technology  

DOE Green Energy (OSTI)

This session at the Geothermal Energy Program Review X: Geothermal Energy and the Utility Market consisted of five papers: ''Reservoir Technology'' by Joel L. Renner; ''LBL Research on the Geysers: Conceptual Models, Simulation and Monitoring Studies'' by Gudmundur S. Bodvarsson; ''Geothermal Geophysical Research in Electrical Methods at UURI'' by Philip E. Wannamaker; ''Optimizing Reinjection Strategy at Palinpinon, Philippines Based on Chloride Data'' by Roland N. Horne; ''TETRAD Reservoir Simulation'' by G. Michael Shook

Renner, Joel L.; Bodvarsson, Gudmundur S.; Wannamaker, Philip E.; Horne, Roland N.; Shook, G. Michael

1992-01-01T23:59:59.000Z

322

Environmental resources of selected areas of Hawaii: Geological hazards  

DOE Green Energy (OSTI)

This report has been prepared to make available and archive the background scientific data and related information collected on geologic hazards during the preparation of the environmental impact statement (EIS) for Phases 3 and 4 of the Hawaii Geothermal Project (HGP) as defined by the state of Hawaii in its April 1989 proposal to Congress. The US Department of Energy (DOE) published a notice withdrawing its Notice of Intent to prepare the HGP-EIS. Since the state of Hawaii is no longer pursuing or planning to pursue the HGP, DOE considers the project to be terminated. This report presents a review of current information on geologic hazards in the Hawaiian Islands. Interrelationships among these hazards are discussed. Probabilities of occurrence of given geologic hazards are provided in various regions where sufficient geologic or historical data are available. Most of the information contained herein is compiled from recent US Geological Survey (USGS) publications and USGS open-file reports related to this project. This report describes the natural geologic hazards present in the area and does not represent an assessment of environmental impacts. Geologic hazards originate both onshore and offshore. Onshore geologic hazards such as volcanic eruptions, earthquakes, surface rupture, landslides, uplift and subsidence occur mainly on the southern third of the island of Hawaii (hereinafter referred to as Hawaii). Offshore geologic hazards are more widely distributed throughout the Hawaiian Islands. Examples of offshore geologic hazards are submarine landslides, turbidity currents, and seismic sea waves (tsunamis).

Staub, W.P.; Reed, R.M.

1995-03-01T23:59:59.000Z

323

An Overview of Geologic Carbon Sequestration Potential in California  

Science Conference Proceedings (OSTI)

As part of the West Coast Regional Carbon Sequestration Partnership (WESTCARB), the California Geological Survey (CGS) conducted an assessment of geologic carbon sequestration potential in California. An inventory of sedimentary basins was screened for preliminary suitability for carbon sequestration. Criteria included porous and permeable strata, seals, and depth sufficient for critical state carbon dioxide (CO{sub 2}) injection. Of 104 basins inventoried, 27 met the criteria for further assessment. Petrophysical and fluid data from oil and gas reservoirs was used to characterize both saline aquifers and hydrocarbon reservoirs. Where available, well log or geophysical information was used to prepare basin-wide maps showing depth-to-basement and gross sand distribution. California's Cenozoic marine basins were determined to possess the most potential for geologic sequestration. These basins contain thick sedimentary sections, multiple saline aquifers and oil and gas reservoirs, widespread shale seals, and significant petrophysical data from oil and gas operations. Potential sequestration areas include the San Joaquin, Sacramento, Ventura, Los Angeles, and Eel River basins, followed by the smaller Salinas, La Honda, Cuyama, Livermore, Orinda, and Sonoma marine basins. California's terrestrial basins are generally too shallow for carbon sequestration. However, the Salton Trough and several smaller basins may offer opportunities for localized carbon sequestration.

Cameron Downey; John Clinkenbeard

2005-10-01T23:59:59.000Z

324

Case studies of current trends in development geology  

SciTech Connect

Traditionally, development geologists have been responsible for studying leases, logs, and cores in detail in support of engineering functions. These responsibilities have grown from defining gross reservoir geometries to understanding subtle differences in reservoirs attributed to stratigraphic and structural complexities, depositional environments, and hydrodynamic processes. To handle these increased responsibilities, expertise has become essential in the areas of computer applications, log analysis, modeling, and management of produced water. Examples of the use and application of each area to projects from fields on the west side of the San Joaquin Valley demonstrate current techniques employed by development geologists and the evolution of a development department within Texaco. A study of a property in the South Belridge field on which 330 wells were drilled over a two-year period illustrates how computer resources have become vital in handling the vast amount of data needed to perform detailed geologic studies. Intricate geologic characterization has become essential to optimizing and defining reservoir performance in several fields: (1) Southeast Lost Hills, a complex diagenetic trap; (2) Buena Vista Hills, where log analysis is needed to make reserve estimates and step-out potential meaningful; (3) Midway-Sunset field, for which detailed geology leads to new field-wide models and future prospects. Increasing environmental concern over waste disposal has required an important involvement of development geologists in the geologic and hydrologic aspects of subsurface injection of produced water and other brines in the Santiago Creek field. Instead of providing a training ground for future explorationists, development geology should be viewed as an alternative career with potential for a much greater demand in the future.

Livingston, N.D.

1987-05-01T23:59:59.000Z

325

An Integrated Study Method For Exploration Of Gas Hydrate Reservoirs In  

Open Energy Info (EERE)

Study Method For Exploration Of Gas Hydrate Reservoirs In Study Method For Exploration Of Gas Hydrate Reservoirs In Marine Areas Jump to: navigation, search GEOTHERMAL ENERGYGeothermal Home Journal Article: An Integrated Study Method For Exploration Of Gas Hydrate Reservoirs In Marine Areas Details Activities (0) Areas (0) Regions (0) Abstract: We propose an integrated study method for exploration of gas hydrate reservoirs in marine areas. This method combines analyses of geology, seismology, and geochemistry. First, geological analysis is made using data of material sources, structures, sediments, and geothermal regimes to determine the hydrocarbon-formation conditions of gas hydrate in marine areas. Then analyses of seismic attributes,such as BSR, AVO, and BZ as well as forward modeling are conducted to predict the potential

326

Shale Reservoir Characterization | Department of Energy  

Energy.gov (U.S. Department of Energy (DOE)) Indexed Site

Oil & Gas » Shale Gas » Shale Reservoir Oil & Gas » Shale Gas » Shale Reservoir Characterization Shale Reservoir Characterization Geologist examining the base of the Marcellus Shale at an outcrop near Bedford, PA. Geologist examining the base of the Marcellus Shale at an outcrop near Bedford, PA. Gas-producing shales are predominantly composed of consolidated clay-sized particles with a high organic content. High subsurface pressures and temperatures convert the organic matter to oil and gas, which may migrate to conventional petroleum traps and also remains within the shale. However, the clay content severely limits gas and fluid flow within the shales. It is, therefore, necessary to understand the mineral and organic content, occurrence of natural fractures, thermal maturity, shale volumes, porosity

327

Optimizing Development Strategies to Increase Reserves in Unconventional Gas Reservoirs  

E-Print Network (OSTI)

The ever increasing energy demand brings about widespread interest to rapidly, profitably and efficiently develop unconventional resources, among which tight gas sands hold a significant portion. However, optimization of development strategies in tight gas fields is challenging, not only because of the wide range of depositional environments and large variability in reservoir properties, but also because the evaluation often has to deal with a multitude of wells, limited reservoir information, and time and budget constraints. Unfortunately, classical full-scale reservoir evaluation cannot be routinely employed by small- to medium-sized operators, given its timeconsuming and expensive nature. In addition, the full-scale evaluation is generally built on deterministic principles and produces a single realization of the reservoir, despite the significant uncertainty faced by operators. This work addresses the need for rapid and cost-efficient technologies to help operators determine optimal well spacing in highly uncertain and risky unconventional gas reservoirs. To achieve the research objectives, an integrated reservoir and decision modeling tool that fully incorporates uncertainty was developed. Monte Carlo simulation was used with a fast, approximate reservoir simulation model to match and predict production performance in unconventional gas reservoirs. Simulation results were then fit with decline curves to enable direct integration of the reservoir model into a Bayesian decision model. These integrated tools were applied to the tight gas assets of Unconventional Gas Resources Inc. in the Berland River area, Alberta, Canada.

Turkarslan, Gulcan

2010-08-01T23:59:59.000Z

328

Reservoir and injection technology and Heat Extraction Project  

DOE Green Energy (OSTI)

For the Stanford Geothermal Program in the fiscal year 1989, the task areas include predictive modeling of reservoir behavior and tracer test interpretation and testing. Major emphasis is in reservoir technology, reinjection technology, and heat extraction. Predictive modeling of reservoir behavior consists of a multi-pronged approach to well test analysis under a variety of conditions. The efforts have been directed to designing and analyzing well tests in (1) naturally fractured reservoirs; (2) fractured wells; (3) complex reservoir geometries; and, (4) gas reservoirs including inertial and other effects. The analytical solutions for naturally fractured reservoirs are determined using fracture size distribution. In the study of fractured wells, an elliptical coordinate system is used to obtain semi-analytical solutions to finite conductivity fractures. Effort has also been directed to the modeling and creation of a user friendly computer program for steam/gas reservoirs including wellbore storage, skin and non-Darcy flow effects. This work has a complementary effort on modeling high flow rate wells including inertial effects in the wellbore and fractures. In addition, work on gravity drainage systems is being continued.

Horne, R.N.; Ramey, H.H. Jr.; Miller, F.G.; Brigham, W.E.; Kruger, P.

1989-12-31T23:59:59.000Z

329

Feasibility of waterflooding Soku E7000 gas-condensate reservoir  

E-Print Network (OSTI)

We performed a simple 3D compositional reservoir simulation study to examine the possibility of waterflooding the Soku E7 gas-condensate reservoir. This study shows that water injection results in higher condensate recovery than natural depletion. To achieve this recovery, the reservoir should return to natural depletion after four years of water injection, before water invades the producing wells. Factors that affect the effectiveness of water injection in this reservoir include aquifer strength, reservoir property distribution, timing of the start of injection, and intra-reservoir shale thickness and continuity. Sensitivity analyses used to quantify the effects of these factors on condensate recovery indicate the need to acquire more production, pressure and log data to reduce the present large uncertainty on aquifer strength before proceeding on waterflooding this reservoir. The study also shows that the injection scheme should be implemented as soon as possible to avoid further loss of condensate recovery. The result of this study is applicable to other gas condensate reservoirs in the Niger delta with similar depositional environments.

Ajayi, Arashi

2002-01-01T23:59:59.000Z

330

Texas - RRC District 4 Onshore Natural Gas, Wet After Lease ...  

U.S. Energy Information Administration (EIA)

Texas - RRC District 4 Onshore Natural Gas, Wet After Lease Separation New Reservoir Discoveries in Old Fields (Billion Cubic Feet)

331

Isotopic identification of leakage gas from underground storage reservoirs. Progress report  

SciTech Connect

The Illinois State Geological Survey reports that in areas where bacteriogenic methane occurs in the near-surface groundwater, isotopic analysis of methane reliably distinguishes this gas from gas that has leaked from underground storage reservoirs. Bacteriogenic methane generally has an isotopic-carbon composition of -64 to -90 per mil, whereas the pipeline and reservoir gases analyzed thus far have all had isotopic-carbon compositions in the range of -40 to -46 per mil.

Coleman, D.D.; Meents, W.F.; Liu, C.L.; Keogh, R.A.

1977-01-01T23:59:59.000Z

332

RATE DECLINE ANALYSIS FOR NATURALLY FRACTURED RESERVOIRS  

E-Print Network (OSTI)

differential equation gives: 1 6 porn = -&(to) (7; - 1) +P Df (A38) Differentiating Eqn. A.88, evaluating at V the matrix radius: #12;APPENDIX A. DERNATION OF SOLUTION 58 Then: & ( f ~ ) l o v g = 9( P D ~-porn). Eqns. A

Stanford University

333

Optimal Geological Enviornments for Carbon Dioxide Storage in Saline Formations  

NLE Websites -- All DOE Office Websites (Extended Search)

susan D. Hovorka susan D. Hovorka Principal Investigator University of Texas at Austin Bureau of Economic Geology 10100 Burnet Road, Bldg. 130 P.O. Box X Austin, TX 78713 512-471-4863 susan.hovorka@beg.utexas.edu Optimal GeOlOGical envirOnments fOr carbOn DiOxiDe stOraGe in saline fOrmatiOns Background For carbon dioxide (CO 2 ) sequestration to be a successful component of the United States emissions reduction strategy, there will have to be a favorable intersection of a number of factors, such as the electricity market, fuel source, power plant design and operation, capture technology, a suitable geologic sequestration site, and a pipeline right-of-way from the plant to the injection site. The concept of CO 2 sequestration in saline water-bearing formations (saline reservoirs), isolated at

334

GEOTHERMAL RESERVOIR SIMULATIONS WITH SHAFT79  

E-Print Network (OSTI)

that well blocks must geothermal reservoir studies, paperof Califomia. LBL-10066 GEOTHERMAL RESERVOIR SIMULATIONSbe presented at the Fifth Geothermal Reservoir Engineering

Pruess, Karsten

2012-01-01T23:59:59.000Z

335

Seismic and Rockphysics Diagnostics of Multiscale Reservoir Textures  

SciTech Connect

This final technical report summarizes the results of the work done in this project. The main objective was to quantify rock microstructures and their effects in terms of elastic impedances in order to quantify the seismic signatures of microstructures. Acoustic microscopy and ultrasonic measurements were used to quantify microstructures and their effects on elastic impedances in sands and shales. The project led to the development of technologies for quantitatively interpreting rock microstructure images, understanding the effects of sorting, compaction and stratification in sediments, and linking elastic data with geologic models to estimate reservoir properties. For the public, ultimately, better technologies for reservoir characterization translates to better reservoir development, reduced risks, and hence reduced energy costs.

Gary Mavko

2005-07-01T23:59:59.000Z

336

Effects of capillarity and vapor adsorption in the depletion of vapor-dominated geothermal reservoirs  

DOE Green Energy (OSTI)

Vapor-dominated geothermal reservoirs in natural (undisturbed) conditions contain water as both vapor and liquid phases. The most compelling evidence for the presence of distributed liquid water is the observation that vapor pressures in these systems are close to saturated vapor pressure for measured reservoir temperatures (White et al., 1971; Truesdell and White, 1973). Analysis of natural heat flow conditions provides additional, indirect evidence for the ubiquitous presence of liquid. From an analysis of the heat pipe process (vapor-liquid counterflow) Preuss (1985) inferred that effective vertical permeability to liquid phase in vapor-dominated reservoirs is approximately 10{sup 17} m{sup 2}, for a heat flux of 1 W/m{sup 2}. This value appears to be at the high end of matrix permeabilities of unfractured rocks at The Geysers, suggesting that at least the smaller fractures contribute to liquid permeability. For liquid to be mobile in fractures, the rock matrix must be essentially completely liquid-saturated, because otherwise liquid phase would be sucked from the fractures into the matrix by capillary force. Large water saturation in the matrix, well above the irreducible saturation of perhaps 30%, has been shown to be compatible with production of superheated steam (Pruess and Narasimhan, 1982). In response to fluid production the liquid phase will boil, with heat of vaporization supplied by the reservoir rocks. As reservoir temperatures decline reservoir pressures will decline also. For depletion of ''bulk'' liquid, the pressure would decline along the saturated vapor pressure curve, while for liquid held by capillary and adsorptive forces inside porous media, an additional decline will arise from ''vapor pressure lowering''. Capillary pressure and vapor adsorption effects, and associated vapor pressure lowering phenomena, have received considerable attention in the geothermal literature, and also in studies related to geologic disposal of heat generating nuclear wastes, and in the drying of porous materials. Geothermally oriented studies were presented by Chicoine et al. (1977), Hsieh and Ramey (1978, 1981), Herkelrath et al. (1983), and Nghiem and Ramey (1991). Nuclear waste-related work includes papers by Herkelrath and O'Neal (1985), Pollock (1986), Eaton and Bixler (1987), Pruess et al. (1990), Nitao (1990), and Doughty and E'ruess (1991). Applications to industrial drying of porous materials have been discussed by Hamiathy (1969) arid Whitaker (1977). This paper is primarily concerned with evaluating the impact of vapor pressure lowering (VPL) effects on the depletion behavior of vapor-dominated reservoirs. We have examined experimental data on vapor adsorption and capillary pressures in an effort to identify constitutive relationships that would be applicable to the tight matrix rocks of vapor-dominated systems. Numerical simulations have been performed to evaluate the impact of these effects on the depletion of vapor-dominated reservoirs.

Pruess, Karsten; O'Sullivan, Michael

1992-01-01T23:59:59.000Z

337

Method of detecting leakage from geologic formations used to sequester CO.sub.2  

DOE Patents (OSTI)

The invention provides methods for the measurement of carbon dioxide leakage from sequestration reservoirs. Tracer moieties are injected along with carbon dioxide into geological formations. Leakage is monitored by gas chromatographic analyses of absorbents. The invention also provides a process for the early leak detection of possible carbon dioxide leakage from sequestration reservoirs by measuring methane (CH.sub.4), ethane (C.sub.2H.sub.6), propane (C.sub.3H.sub.8), and/or radon (Rn) leakage rates from the reservoirs. The invention further provides a method for branding sequestered carbon dioxide using perfluorcarbon tracers (PFTs) to show ownership.

White, Curt (Pittsburgh, PA); Wells, Arthur (Bridgeville, PA); Diehl, J. Rodney (Pittsburgh, PA); Strazisar, Brian (Venetia, PA)

2010-04-27T23:59:59.000Z

338

Artificial nature : water infrastructure and its experience as natural space  

E-Print Network (OSTI)

This work is about water infrastructure and its experience as urban and natural space. It deals with the concepts of nature/geography, technology, and the integral experiential space by analyzing water dams and reservoirs ...

Demirta?, Fatma Asl?han, 1970-

2000-01-01T23:59:59.000Z

339

,"Kentucky Natural Gas Summary"  

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

Gas New Reservoir Discoveries in Old Fields (Billion Cubic Feet)","Kentucky Dry Natural Gas Reserves Estimated Production (Billion Cubic Feet)" 28306,451,1,35,17,,,10,3,0,48...

340

,"Oklahoma Natural Gas Summary"  

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

Gas New Reservoir Discoveries in Old Fields (Billion Cubic Feet)","Oklahoma Dry Natural Gas Reserves Estimated Production (Billion Cubic Feet)" 28306,13889,36,837,1016,,,1129,181,...

Note: This page contains sample records for the topic "natural geological reservoir" from the National Library of EnergyBeta (NLEBeta).
While these samples are representative of the content of NLEBeta,
they are not comprehensive nor are they the most current set.
We encourage you to perform a real-time search of NLEBeta
to obtain the most current and comprehensive results.


341

,"Florida Natural Gas Summary"  

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

Gas New Reservoir Discoveries in Old Fields (Billion Cubic Feet)","Florida Dry Natural Gas Reserves Estimated Production (Billion Cubic Feet)" 28306,151,-1,1,6,,,0,0,0,36...

342

,"Wyoming Natural Gas Summary"  

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

Gas New Reservoir Discoveries in Old Fields (Billion Cubic Feet)","Wyoming Dry Natural Gas Reserves Estimated Production (Billion Cubic Feet)" 28306,6305,-3,226,165,,,884,391,10,...

343

,"Ohio Natural Gas Summary"  

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

Gas New Reservoir Discoveries in Old Fields (Billion Cubic Feet)","Ohio Dry Natural Gas Reserves Estimated Production (Billion Cubic Feet)" 28306,495,-3,48,11,,,113,0,31,60...

344

,"Kansas Natural Gas Summary"  

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

Gas New Reservoir Discoveries in Old Fields (Billion Cubic Feet)","Kansas Dry Natural Gas Reserves Estimated Production (Billion Cubic Feet)" 28306,11457,-3,122,171,,,219,21,7,7...

345

,"Utah Natural Gas Summary"  

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

Gas New Reservoir Discoveries in Old Fields (Billion Cubic Feet)","Utah Dry Natural Gas Reserves Estimated Production (Billion Cubic Feet)" 28306,877,0,37,79,,,93,32,2,62...

346

Improved Miscible Nitrogen Flood Performance Utilizing Advanced Reservoir Characterization and Horizontal Laterals in a Class I Reservoir - East Binger (Marchand) Unit  

Science Conference Proceedings (OSTI)

The DOE-sponsored project at the East Binger Unit is an investigation into the benefits of reservoir characterization and horizontal wells in this particular setting of geologic and recovery method. The geologic setting is a tight (average porosity of 7% and average permeability of less than 1 millidarcy) Pennsylvanian-age sandstone at about 10,000 feet, and the recovery method is a miscible nitrogen flood. The projected oil recovery of the East Binger Unit, prior to the initiation of this project, was about 25%. Gravity segregation of nitrogen and crude oil was believed to be the principal cause of the poor sweep efficiency, and it was envisioned that with horizontal producing wells in the lower portion of the reservoir and horizontal injection wells near the top, the process could be converted from a lateral displacement process to a vertical displacement/gravity assisted process. Through the characterization and field development work completed in Budget Periods 1 and 2, Binger Operations, LLC (BOL) has developed a different interpretation of the sweep problem as well as a different approach to improving recovery. The sweep problem is now believed to be one of an areal nature, due to a combination of natural and hydraulic fracturing. Vertical wells have provided a much better economic return than have the horizontal wells. The natural and hydraulic fracturing manifests itself as a direction of higher permeability, and the flood is being converted to a line drive flood aligned with this orientation. Consistent with this concept, horizontal wells have been drilled along the line of the fracture orientation, such that hydraulic fracturing leads to 'longitudinal' fractures, in line with the wellbore. As such, the hydraulically fractured horizontal wells are not significantly different than hydraulically fractured vertical wells - save for the potential for a much longer fracture face. This Topical Report contains data from new wells, plus new and updated production, pressure, and gas analysis data that was not included in the Topical Report provided at the end of Budget Period 1. The analysis and interpretation of these data are provided in the many technical reports submitted throughout this project.

Joe Sinner

2004-06-30T23:59:59.000Z

347

Interdisciplinary study of reservoir compartments. [Quarterly report, April 1, 1994--June 30, 1994  

SciTech Connect

This DOE research project was established to document the integrated team approach for solving reservoir engineering problems. A field study integrating the disciplines of geology, geophysics, and petroleum engineering will be the mechanism for documenting the integrated approach. This is an area of keen interest to the oil and gas industry. The goal will be to provide tools and approaches that can be used to detect reservoir compartments, reach a better reserve estimate, and improve profits early in the life of a field. Progress reports are presented for the following tasks: reservoir selection and data gathering; outcrop/core/log analysis/ and correlations, internal architecture description; seismic analysis; and permeability experimental work.

Van Kirk, C.W.; Thompson, R.S.

1994-07-26T23:59:59.000Z

348

Application of Integrated Reservoir Management and Reservoir Characterization to Optimize Infill Drillings. Annual technical progress report, June 13, 1996 to June 12, 1998  

Science Conference Proceedings (OSTI)

Infill drilling of wells on a uniform spacing, without regard to reservoir performance and characterization, does 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. Other technologies, such as inter-well injection tracers and magnetic flow conditioners, can also aid in the efficient evaluation and operation of both injection and producing wells. The purpose of this project was to demonstrate useful and cost effective methods of exploitation of the shallow shelf carbonate reservoirs of the Permian Basin located in West Texas.

Nevans, Jerry W.; Blasingame, Tom; Doublet, Louis; Kelkar, Mohan; Freeman, George; Callard, Jeff; Moore, David; Davies, David; Vessell, Richard; Pregger, Brian; Dixon, Bill

1999-04-27T23:59:59.000Z

349

Characterization of oil and gas reservoir heterogeneity  

SciTech Connect

Research described In this report addresses the internal architecture of two specific reservoir types: restricted-platform carbonates and fluvial-deltaic sandstones. Together, these two reservoir types contain more than two-thirds of the unrecovered mobile oil remaining ill Texas. The approach followed in this study was to develop a strong understanding of the styles of heterogeneity of these reservoir types based on a detailed outcrop description and a translation of these findings into optimized recovery strategies in select subsurface analogs. Research targeted Grayburg Formation restricted-platform carbonate outcrops along the Algerita Escarpment and In Stone Canyon In southeastern New Mexico and Ferron deltaic sandstones in central Utah as analogs for the North Foster (Grayburg) and Lake Creek (Wilcox) units, respectively. In both settings, sequence-stratigraphic style profoundly influenced between-well architectural fabric and permeability structure. It is concluded that reservoirs of different depositional origins can therefore be categorized Into a heterogeneity matrix'' based on varying intensity of vertical and lateral heterogeneity. The utility of the matrix is that it allows prediction of the nature and location of remaining mobile oil. Highly stratified reservoirs such as the Grayburg, for example, will contain a large proportion of vertically bypassed oil; thus, an appropriate recovery strategy will be waterflood optimization and profile modification. Laterally heterogeneous reservoirs such as deltaic distributary systems would benefit from targeted infill drilling (possibly with horizontal wells) and improved areal sweep efficiency. Potential for advanced recovery of remaining mobile oil through heterogeneity-based advanced secondary recovery strategies In Texas is projected to be an Incremental 16 Bbbl. In the Lower 48 States this target may be as much as 45 Bbbl at low to moderate oil prices over the near- to mid-term.

Tyler, N.; Barton, M.D.; Bebout, D.G.; Fisher, R.S.; Grigsby, J.D.; Guevara, E.; Holtz, M.; Kerans, C.; Nance, H.S.; Levey, R.A.

1992-10-01T23:59:59.000Z

350

NATURAL GAS RESOURCES IN DEEP SEDIMENTARY BASINS  

SciTech Connect

From a geological perspective, deep natural gas resources are generally defined as resources occurring in reservoirs at or below 15,000 feet, whereas ultra-deep gas occurs below 25,000 feet. From an operational point of view, ''deep'' is often thought of in a relative sense based on the geologic and engineering knowledge of gas (and oil) resources in a particular area. Deep gas can be found in either conventionally-trapped or unconventional basin-center accumulations that are essentially large single fields having spatial dimensions often exceeding those of conventional fields. Exploration for deep conventional and unconventional basin-center natural gas resources deserves special attention because these resources are widespread and occur in diverse geologic environments. In 1995, the U.S. Geological Survey estimated that 939 TCF of technically recoverable natural gas remained to be discovered or was part of reserve appreciation from known fields in the onshore areas and State waters of the United. Of this USGS resource, nearly 114 trillion cubic feet (Tcf) of technically-recoverable gas remains to be discovered from deep sedimentary basins. Worldwide estimates of deep gas are also high. The U.S. Geological Survey World Petroleum Assessment 2000 Project recently estimated a world mean undiscovered conventional gas resource outside the U.S. of 844 Tcf below 4.5 km (about 15,000 feet). Less is known about the origins of deep gas than about the origins of gas at shallower depths because fewer wells have been drilled into the deeper portions of many basins. Some of the many factors contributing to the origin of deep gas include the thermal stability of methane, the role of water and non-hydrocarbon gases in natural gas generation, porosity loss with increasing thermal maturity, the kinetics of deep gas generation, thermal cracking of oil to gas, and source rock potential based on thermal maturity and kerogen type. Recent experimental simulations using laboratory pyrolysis methods have provided much information on the origins of deep gas. Technologic problems are one of the greatest challenges to deep drilling. Problems associated with overcoming hostile drilling environments (e.g. high temperatures and pressures, and acid gases such as CO{sub 2} and H{sub 2}S) for successful well completion, present the greatest obstacles to drilling, evaluating, and developing deep gas fields. Even though the overall success ratio for deep wells is about 50 percent, a lack of geological and geophysical information such as reservoir quality, trap development, and gas composition continues to be a major barrier to deep gas exploration. Results of recent finding-cost studies by depth interval for the onshore U.S. indicate that, on average, deep wells cost nearly 10 times more to drill than shallow wells, but well costs and gas recoveries vary widely among different gas plays in different basins. Based on an analysis of natural gas assessments, many topical areas hold significant promise for future exploration and development. One such area involves re-evaluating and assessing hypothetical unconventional basin-center gas plays. Poorly-understood basin-center gas plays could contain significant deep undiscovered technically-recoverable gas resources.

Thaddeus S. Dyman; Troy Cook; Robert A. Crovelli; Allison A. Henry; Timothy C. Hester; Ronald C. Johnson; Michael D. Lewan; Vito F. Nuccio; James W. Schmoker; Dennis B. Riggin; Christopher J. Schenk

2002-02-05T23:59:59.000Z

351

Optimizing Fracture Treatments in a Mississippian "Chat" Reservoir, South-Central Kansas  

Science Conference Proceedings (OSTI)

This project is a collaboration of Woolsey Petroleum Corporation (a small independent operator) and the Kansas Geological Survey. The project will investigate geologic and engineering factors critical for designing hydraulic fracture treatments in Mississippian ''chat'' reservoirs. Mississippian reservoirs, including the chat, account for 159 million m3 (1 billion barrels) of the cumulative oil produced in Kansas. Mississippian reservoirs presently represent {approx}40% of the state's 5.6*106m3 (35 million barrels) annual production. Although geographically widespread, the ''chat'' is a heterogeneous reservoir composed of chert, cherty dolomite, and argillaceous limestone. Fractured chert with micro-moldic porosity is the best reservoir in this 18- to 30-m-thick (60- to 100-ft) unit. The chat will be cored in an infill well in the Medicine Lodge North field (417,638 m3 [2,626,858 bbls] oil; 217,811,000 m3 [7,692,010 mcf] gas cumulative production; discovered 1954). The core and modern wireline logs will provide geological and petrophysical data for designing a fracture treatment. Optimum hydraulic fracturing design is poorly defined in the chat, with poor correlation of treatment size to production increase. To establish new geologic and petrophysical guidelines for these treatments, data from core petrophysics, wireline logs, and oil-field maps will be input to a fracture-treatment simulation program. Parameters will be established for optimal size of the treatment and geologic characteristics of the predicted fracturing. The fracturing will be performed and subsequent wellsite tests will ascertain the results for comparison to predictions. A reservoir simulation program will then predict the rate and volumetric increase in production. Comparison of the predicted increase in production with that of reality, and the hypothetical fracturing behavior of the reservoir with that of its actual behavior, will serve as tests of the geologic and petrophysical characterization of the oil field. After this feedback, a second well will be cored and logged, and procedure will be repeated to test characteristics determined to be critical for designing cost-effective fracture treatments. Most oil and gas production in Kansas, and that of the Midcontinent oil industry, is dominated by small companies. The overwhelming majority of these independent operators employ less than 20 people. These companies have limited scientific and engineering expertise and they are increasingly needing guidelines and technical examples that will help them to not be wasteful of their limited financial resources and petroleum reserves. To aid these operators, the technology transfer capabilities of the Kansas Geological Survey will disseminate the results of this study to the local, regional, and national oil industry. Internet access, seminars, presentations, and publications by Woolsey Petroleum Company and Kansas Geological Survey geologists and engineers are anticipated.

K. David Newell; Saibal Bhattacharya; Alan Byrnes; W. Lynn Watney; Willard Guy

2005-10-01T23:59:59.000Z

352

Reinjection into geothermal reservoirs  

DOE Green Energy (OSTI)

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)

Bodvarsson, G.S.; Stefansson, V.

1987-08-01T23:59:59.000Z

353

Identification and evaluation of fluvial-dominated deltaic (Class I oil) reservoirs in Oklahoma. Quarterly technical progress report, April 1, 1993--June 30, 1993  

Science Conference Proceedings (OSTI)

The Oklahoma Geological Survey (OGS), the Geological Information Systems department, and the School of Petroleum and Geological Engineering at the University of Oklahoma are engaging in a program to identify and address Oklahoma`s oil recovery opportunities in fluvial-dominated deltaic (FDD) reservoirs. This program includes the systematic and comprehensive collection and evaluation of information on all of Oklahoma`s FDD reservoirs and the recovery-technologies that have been (or could be) applied to those reservoirs with commercial success. This data collection and evaluation effort will be the foundation for an aggressive, multifaceted technology transfer program that is designed to support all of Oklahoma`s oil industry, with particular emphasis on smaller companies and independent operators in their attempts to maximize the economic producibility of FDD reservoirs. Specifically, this project will identify all FDD oil reservoirs in the State; group those reservoirs into plays that have similar depositional and subsequent geologic histories; collect, organize and analyze all available data; conduct characterization and simulation studies on selected reservoirs in each play; and implement a technology transfer program targeted to the operators of FDD reservoirs to sustain the life expectancy of existing wells with the ultimate objective of increasing oil recovery.

Mankin, G.J. [Oklahoma Geological Survey, Norman, OK (United States); Banken, M.K. [Oklahoma Univ., Norman, OK (United States)

1993-09-28T23:59:59.000Z

354

Identification and evaluation of fluvial-dominated deltaic (Class I oil) reservoirs in Oklahoma. Quarterly technical progress report, January 1, 1993--March 31, 1993  

Science Conference Proceedings (OSTI)

The Oklahoma Geological Survey (OGS), the Geological Information Systems department, and the School of Petroleum and Geological Engineering at the University of Oklahoma have engaged in a program to identify and address Oklahoma`s oil recovery opportunities in fluvial-dominated deltaic (FDD) reservoirs. This program includes the systematic and comprehensive collection and evaluation of information on all of Oklahoma`s FDD reservoirs and the recovery technologies that have been (or could be) applied to those reservoirs with commercial success. This data collection and evaluation effort will be the foundation for an aggressive, multifaceted technology transfer program that is designed to support all of Oklahoma`s oil industry, with particular emphasis on smaller companies and independent operators in their attempts to maximize the economic producibility of FDD reservoirs. Specifically, this project will identify all FDD oil reservoirs in the State; group those reservoirs into plays that have similar depositional and subsequent geologic histories; collect, organize and analyze all available data; conduct characterization and simulation studies on selected reservoirs in each play; and implement a technology transfer program targeted to the operators of FDD reservoirs to sustain the life expectancy of existing wells with the ultimate objective of increasing oil recovery.

Mankin, C.J. [Oklahoma Geological Survey, Norman, OK (United States); Grasmick, M.K. [Oklahoma Univ., Norman, OK (United States)

1993-06-04T23:59:59.000Z

355

Identification and evaluation of fluvial-dominated deltaic (Class 1 oil) reservoirs in Oklahoma. Quarterly technical progress report, January 1, 1995--March 31, 1995  

Science Conference Proceedings (OSTI)

The Oklahoma Geological Survey (OGS), the Geological Information Systems department, and the School of Petroleum and Geological Engineering at the University of Oklahoma are engaging in a program to identify and address Oklahoma`s oil recovery opportunities in fluvial-dominated deltaic (FDD) reservoirs. This program includes the systematic and comprehensive collection and evaluation of information on all of Oklahoma`s FDD reservoirs and the recovery technologies that have been (or could be) applied to those reservoirs with commercial success. This data collection and evaluation effort will be the foundation for an aggressive, multifaceted technology transfer program that is designed to support all of Oklahoma`s oil industry, with particular emphasis on smaller companies and independent operators in their attempts to maximize the economic producibility of FDD reservoirs. Specifically, this project will identify all FDD oil reservoirs in the State; group those reservoirs into plays that have similar depositional and subsequent geologic histories; collect, organize and analyze all available data; conduct characterization and simulation studies on selected reservoirs in each play; and implement a technology transfer program targeted to the operators of FDD reservoirs to sustain the life expectancy of existing wells with the ultimate objective of increasing oil recovery. The elements of the technology transfer program include developing and publishing play portfolios, holding workshops to release play analyses and identify opportunities in each of the plays, and establishing a computer laboratory that is available for industry users.

Mankin, C.J. [Oklahoma Geological Survey, Norman, OK (United States); Banken, M.K. [Oklahoma Univ., Norman, OK (United States)

1995-07-07T23:59:59.000Z

356

Identification and evaluation of fluvial-dominated deltaic (class 1 oil) reservoirs in Oklahoma. Quarterly technical progress report, July 1, 1993--September 30, 1993  

Science Conference Proceedings (OSTI)

The Oklahoma Geological Survey (OGS), the Geological Information Systems department, and the School of Petroleum and Geological Engineering at the University of Oklahoma are engaging in a program to identify and address Oklahoma`s oil recovery opportunities in fluvial-dominated deltaic (FDD) reservoirs. This program includes the systematic and comprehensive collection and evaluation of information on all of Oklahoma`s FDD reservoirs and the recovery technologies that have been (or could be) applied to those reservoirs with commercial success. This data collection and evaluation effort will be the foundation for an aggressive, multifaceted technology transfer program that is designed to support all of Oklahoma`s oil industry, with particular emphasis on smaller companies and independent operators in their attempts to maximize the economic producibility of FDD reservoirs. Specifically, this project will identify all FDD oil reservoirs in the State; group those reservoirs into plays that have similar depositional and subsequent geologic histories; collect, organize and analyze all available data; conduct characterization and simulation studies on selected reservoirs in each play; and implement a technology transfer program targeted to the operators of FDD reservoirs to sustain the life expectancy of existing wells with the ultimate objective of increasing oil recovery.

Mankin, C.J. [Oklahoma Geological Survey, Norman, OK (United States); Banken, M.K. [Oklahoma Univ., Norman, OK (United States)

1994-04-28T23:59:59.000Z

357

Identification and evaluation of fluvial-dominated deltaic (Class 1 oil) reservoirs in Oklahoma. Quarterly technical progress report, October 1, 1994--December 31, 1994  

Science Conference Proceedings (OSTI)

The Oklahoma Geological Survey (OGS), the Geological Information Systems department, and the School of Petroleum and Geological Engineering at the University of Oklahoma are engaging in a program to identify and address Oklahoma`s oil recovery opportunities in fluvial-dominated deltaic (FDD) reservoirs. This program includes the systematic and comprehensive collection and evaluation of information on all of Oklahoma`s FDD reservoirs and the recovery technologies that have been (or could be) applied to those reservoirs with commercial success. This data collection and evaluation effort will be the foundation for an aggressive, multifaceted technology transfer program that is designed to support all of Oklahoma`s oil industry, with particular emphasis on smaller companies and independent operators in their attempts to maximize the economic producibility of FDD reservoirs. Specifically, this project will identify all FDD oil reservoirs in the State; group those reservoirs into plays that have similar depositional and subsequent geologic histories; collect, organize and analyze all available data; conduct characterization and simulation studies on selected reservoirs in each play; and implement a technology transfer program targeted to the operators of FDD reservoirs to sustain the life expectancy of existing wells with the ultimate objective of increasing oil recovery.

Mankin, C.J. [Oklahoma Geological Survey, Norman, OK (United States); Banken, M.K. [Oklahoma Univ., Norman, OK (United States)

1995-07-06T23:59:59.000Z

358

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

SciTech Connect

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.

Poston, S.W.

1991-12-31T23:59:59.000Z

359

An integrated study of the reservoir performance in the Area Central Norte (ACN) region of the Tordillo Field (Argentina)  

E-Print Network (OSTI)

The Tordillo Field is located within the San Jorge Basin of southern Argentina. The field is located within a small, dominantly extension basin, and is operated by Tecpetrol S.A., a domestic private oil company. The field produces from the El TreboL Comodoro Rivadavia, and Mina El Carmen Formations and is estimated to contain approximately 1,800 MMSTB of in-place oil. The Area Central Norte (ACN) region is a designated portion of the TordiHo Field in which a pilot waterflood was initiated in September 1993. There are immediate plans for expanding the pilot waterflood, and therefore, it is imperative that we evaluate the reservoir properties, as well as the reservoir production potential in order to design the most effective field development plan. Our integrated study of reservoir performance in the ACN pilot area, combining the geological, engineering, and reservoir performance data, is utilized to characterize the reservoir and to develop an appropriate reservoir management plan. This study win be used to determine the feasibility of expanding secondary recovery efforts throughout the Tordiflo Field by developing a reservoir description that includes the reservoir structure, rock and fluid properties, and the performance potential of the reservoir. The main focus of this work is to evaluate primary and secondary well performance in a highly stratified sequence of oil producing sands. In this study, we use rigorous methods to analyze and interpret production rate, injection rate, and pressure data from oil and water injection wells using decline type curves and estimated ultimate recovery (EUR) analysis. These methods are shown to yield excellent results for a variety of field conditions, without regard to the structure of the reservoir (shape and size), or the reservoir drive mechanism(s). Results of these analyses include the following: eservo rties: 0 Fonnation permeability, k Skin factor, s, for near-well damage or stimulation In-pplace fluid volumes: Original oil-in-place, N Reservoir drainage area, A Movable oil at current conditions, Np,,,,,, We examined the available core and modem well log data to develop an understanding for the petrophysical (k and 0) properties of the reservoir. These results will help us determine if reservoir performance is directly influenced by the geologic structure and flow characteristics of the reservoir. By combing the geological, petrophysical, and reservoir performance data in this manner, we are able to develop an integrated reservoir description for future developments as well as production optimization.

Tuvio, Raul

1997-01-01T23:59:59.000Z

360

Geological Sciences College of Science  

E-Print Network (OSTI)

postgraduate studies in Engineering Geology. `From going to mines and quarries, looking at what the job entails to his childhood when he would enjoy visiting mines and caves while on holidays around the UK, learning Geological Evolution of NZ and Antarctica GEOL 483 Coal & Petroleum Geology GEOL488 Special Topics

Hickman, Mark

Note: This page contains sample records for the topic "natural geological reservoir" from the National Library of EnergyBeta (NLEBeta).
While these samples are representative of the content of NLEBeta,
they are not comprehensive nor are they the most current set.
We encourage you to perform a real-time search of NLEBeta
to obtain the most current and comprehensive results.


361

OPTIMIZATION OF NATURAL GAS FIELD DEVELOPMENT USING ARTIFICIAL NEURAL NETWORKS.  

E-Print Network (OSTI)

??Field development of natural gas reservoirs is one of the main aspects of exploration and production of natural gas for oil and gas operators. After (more)

Olatunji, Adewale

2010-01-01T23:59:59.000Z

362

Characterization of Roabiba Sandstones Reservoir in Bintuni Field, Papua, Indonesia  

E-Print Network (OSTI)

Bintuni Field has two Middle Jurassic gas reservoirs, Upper and Lower Roabiba Sandstone reservoirs, with the estimated reserve from eight appraisal drilled wells of 6.08 tcf. The field has not been producing commercially. The main gas reservoir is the Upper Roabiba Sandstone. It was deposited in a tidal-dominated shoreface delta and consists of a moderately sorted, fine to medium grain, quartzarenite with average porosity of 12% and average permeability of 250 md. Lower Roabiba Sandstone was deposited in estuarine channel and marsh and consists of lower fine to lower coarse grained quartzarenites with average porosity of 12% and permeability 215 md. This study is considered necessary since the field is considered to be a giant field and there are a limited number of studies on the Roabiba Sandstones reservoir specifically in Bintuni Field that have been published. The purpose of this study was to develop geological and petrophysical analysis that will identify reservoir quality and distribution of best, intermediate, and poor reservoir zones by characterizing distribution of porosity-permeability values in lithofacies and mercury injection capillary pressure. The methods to characterize the reservoir included core-based lithofacies determination, well logs analysis, and mercury injection capillary pressure analysis. As a result from core descriptions, three main units of lithofacies could be identified. Lithofacies massive sandstones (ms), slightly bioturbated sandstones (sb1), and crosslaminated sandstones (xls) have the highest average permeability (>100 md) and porosity (>10%). Petrophysical properties from core data show that porosity varies only slightly regardless of lithofacies characteristic whereas permeability variations are greater and correspond closely with the lithofacies. When grouped according to the dominant pore throat dimension, distinct collections or grouping of rocks and their associated lithofacies were observed. Winland plot was engaged to do clustering of rock types since Winland R35 pore port sizes represent "cut off values" for good and bad flow unit quality. The analyses of porositypermeability plots were confirmed with the Winland plot that the best reservoir rock (rock type 1) consists of lithofacies ms, xls, and sb1. From this development, four petrophysical rock types were defined and characterized. Rock type 1 (the best reservoir rock) consists of lithofacies ms, xls, and sb1. Therefore, associated lithofacies in rock type 1 may be used as a pore-proxy rock property for the determination of best reservoir rock and corresponding flow units at the reservoir scale.

Vera, Riene

2009-12-01T23:59:59.000Z

363

CO2 Geologic Storage (Kentucky) | Department of Energy  

Energy.gov (U.S. Department of Energy (DOE)) Indexed Site

CO2 Geologic Storage (Kentucky) CO2 Geologic Storage (Kentucky) CO2 Geologic Storage (Kentucky) < Back Eligibility Industrial Program Info State Kentucky Program Type Industry Recruitment/Support Provider Consultant, Division of Carbon Management Division staff, in partnership with the Kentucky Geological Survey (KGS), continued to support projects to investigate and demonstrate the technical feasibility of geologic storage of carbon dioxide (CO2) in Kentucky. In 2012, KGS conducted a test of carbon dioxide enhanced natural gas recovery in the Devonian Ohio Shale, Johnson County, east Kentucky. During the test, 87 tons of CO2 were injected through perforations in a cased, shut-in shale gas well. Industry partners for this research included Crossrock Drilling, Advanced Resources International, Schlumberger, Ferus Industries, and

364

INTELLIGENT COMPUTING SYSTEM FOR RESERVOIR ANALYSIS AND RISK ASSESSMENT OF THE RED RIVER FORMATION  

SciTech Connect

Integrated software has been written that comprises the tool kit for the Intelligent Computing System (ICS). The software tools in ICS have been developed for characterization of reservoir properties and evaluation of hydrocarbon potential using a combination of inter-disciplinary data sources such as geophysical, geologic and engineering variables. The ICS tools provide a means for logical and consistent reservoir characterization and oil reserve estimates. The tools can be broadly characterized as (1) clustering tools, (2) neural solvers, (3) multiple-linear regression, (4) entrapment-potential calculator and (5) file utility tools. ICS tools are extremely flexible in their approach and use, and applicable to most geologic settings. The tools are primarily designed to correlate relationships between seismic information and engineering and geologic data obtained from wells, and to convert or translate seismic information into engineering and geologic terms or units. It is also possible to apply ICS in a simple framework that may include reservoir characterization using only engineering, seismic, or geologic data in the analysis. ICS tools were developed and tested using geophysical, geologic and engineering data obtained from an exploitation and development project involving the Red River Formation in Bowman County, North Dakota and Harding County, South Dakota. Data obtained from 3D seismic surveys, and 2D seismic lines encompassing nine prospective field areas were used in the analysis. The geologic setting of the Red River Formation in Bowman and Harding counties is that of a shallow-shelf, carbonate system. Present-day depth of the Red River formation is approximately 8000 to 10,000 ft below ground surface. This report summarizes production results from well demonstration activity, results of reservoir characterization of the Red River Formation at demonstration sites, descriptions of ICS tools and strategies for their application.

Mark A. Sippel; William C. Carrigan; Kenneth D. Luff; Lyn Canter

2003-11-12T23:59:59.000Z

365

PROCEEDINGS, Thirty-Sixth Workshop on Geothermal Reservoir Engineering Stanford University, Stanford, California, January 31 -February 2, 2011  

E-Print Network (OSTI)

PROCEEDINGS, Thirty-Sixth Workshop on Geothermal Reservoir Engineering Stanford University, Germany iulia.ghergut@geo.uni-goettingen.de ABSTRACT In fluid-based geothermal reservoirs, thermal between "heat exchange area" and RTD features of a geothermal reservoir feel natural, but act highly

Stanford University

366

Hydrological/Geological Studies  

Office of Legacy Management (LM)

.\ .8.2 .\ .8.2 Hydrological/Geological Studies Book 1. Radiochemical Analyses of Water Samples from SelectedT" Streams Wells, Springs and Precipitation Collected During Re-Entry Drilling, Project Rulison-7, 197 1 HGS 8 This page intentionally left blank . . . ... . . . . . . . . , : . . . . . . . . . ' . r - . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . ... . . . . . ..... . - x ..:; . , ' , . . ' . . . . . . !' r:.::. _. . : _ . . : . . . . \ . . ' - \ , : , . . . . . . . . . . . . . il.'; , . . y,.:.: . . . . . . . . ., ' . . ' . , . . . . . . . . . - . . . . . ... . . . . . : . . - . . . . . . . . . . . . . . . . . . . . . . .,. . . . . . . . .. 2 . . . . . . . . . . . ..... . . . . . . . . . . . . , .- , . : , . , . . . . ......... ... ) . . i - . . . . . . . . . . . . . . . . . . Prepared. Under . . . ~ ~ r e e m e n t - No. AT(29-2) -474 for the ~ e v a d a - - Operations Office U. S .. Atomic. ,Energy Commi~ssion

367

Identification and evaluation of fluvial-dominated deltaic (Class I oil) reservoirs in Oklahoma. Quarterly technical progress report, July 1--September 30, 1995  

Science Conference Proceedings (OSTI)

The Oklahoma Geological Survey (OGS), the Geo Information Systems department, and the School of Petroleum and Geological Engineering at the University of Oklahoma are engaged in a program to identify and address Oklahoma`s oil recovery opportunities in fluvial-dominated deltaic (FDD) reservoirs. This program includes the systematic and comprehensive collection and evaluation of information on all of Oklahoma`s FDD reservoirs and the recovery technologies that have been (or could be) applied to those reservoirs with commercial success. This data collection and evaluation effort will be the foundation for an aggressive, multifaceted technology transfer program that is designed to support all of Oklahoma`s oil industry, with particular emphasis on smaller companies and independent operators in their attempts to maximize the economic producibility of FDD reservoirs. Specifically, this project will identify all FDD oil reservoirs in the State; group those reservoirs into plays that have similar depositional origins; collect, organize and analyze all available data conduct characterization and simulation studies on selected reservoirs in each play; and implement a technology transfer program targeted to the operators of FDD reservoirs. Activities were focused primarily on technology transfer elements of the project. This included regional play analysis and mapping, geologic field studies, and reservoir modeling for secondary water flood simulations as used in publication folios and workshops. The computer laboratory was fully operational for operator use. Computer systems design and database development activities were ongoing.

Mankin, C.J. [Oklahoma Geological Survey, Norman, OK (United States); Banken, M.K. [Oklahoma Univ., Norman, OK (United States)

1995-11-30T23:59:59.000Z

368

Status of Blue Ridge Reservoir  

DOE Green Energy (OSTI)

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 Blue Ridge 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 and data available, as well as interview with water resource professionals in various federal, state, and local agencies. Blue Ridge Reservoir is a single-purpose hydropower generating project. When consistent with this primary objective, the reservoir is also operated to benefit secondary objectives including water quality, recreation, fish and aquatic habitat, development of shoreline, aesthetic quality, and other public and private uses that support overall regional economic growth and development. 8 refs., 1 fig.

Not Available

1990-09-01T23:59:59.000Z

369

Reaction Mechanisms in Petroleum: From Experimentation to Upgrading and Geological Conditions  

E-Print Network (OSTI)

Among the numerous questions that arise concerning the exploitation of petroleum from unconventional reservoirs, lie the questions of the composition of hydrocarbons present in deep seated HP-HT reservoirs or produced during in-situ upgrading steps of heavy oils and oil shales. Our research shows that experimental hydrocarbon cracking results obtained in the laboratory cannot be extrapolated to geological reservoir conditions in a simple manner. Our demonstration is based on two examples: 1) the role of the hydrocarbon mixture composition on reaction kinetics (the "mixing effect") and the effects of pressure (both in relationship to temperature and time). The extrapolation of experimental data to geological conditions requires investigation of the free-radical reaction mechanisms through a computed kinetic model. We propose a model that takes into account 52 reactants as of today, and which can be continuously improved by addition of new reactants as research proceeds. This model is complete and detailed enou...

Lannuzel, Frdric; Bounaceur, Roda; Marquaire, Paul-Marie; Michels, Raymond

2009-01-01T23:59:59.000Z

370

Fluvial-deltaic heavy oil reservoir, San Joaquin basin  

SciTech Connect

Unconsolidated arkosic sands deposited in a fluvial-deltaic geologic setting comprise the heavy oil (13/degree/ API gravity) reservoir at South Belridge field. The field is located along the western side of the San Joaquin basin in Kern County, California. More than 6000 closely spaced and shallow wells are the key to producing the estimated 1 billion bbl of ultimate recoverable oil production. Thousands of layered and laterally discontinuous reservoir sands produce from the Pleistocene Tulare Formation. The small scale of reservoir geometries is exploited by a high well density, required for optimal heavy oil production. Wells are typically spaced 200-500 ft (66-164 m) apart and drilled to 1000 ft (328 m) deep in the 14-mi/sup 2/ (36-km/sup 2/) producing area. Successful in-situ combustion, cyclic steaming, and steamflood projects have benefited from the shallow-depth, thick, layered sands, which exhibit excellent reservoir quality. The fundamental criterion for finding another South Belridge field is to realize the extraordinary development potential of shallow, heavy oil reservoirs, even when an unspectacular discovery well is drilled. The trap is a combination of structural and stratigraphic mechanisms plus influence from unconventional fluid-level and tar-seal traps. The depositional model is interpreted as a braid delta sequence that prograded from the nearby basin-margin highlands. A detailed fluvial-deltaic sedimentologic model establishes close correlation between depositional lithofacies, reservoir geometries, reservoir quality, and heavy oil producibility. Typical porosity is 35% and permeability is 3000 md.

Miller, D.D.; McPherson, J.G.; Covington, T.E.

1989-03-01T23:59:59.000Z

371

Source/Sink Matching for U.S. Ethanol Plants and Candidate Deep Geologic Carbon Dioxide Storage Formations  

DOE Green Energy (OSTI)

This report presents data on the 140 existing and 74 planned ethanol production facilities and their proximity to candidate deep geologic storage formations. Half of the existing ethanol plants and 64% of the planned units sit directly atop a candidate geologic storage reservoir. While 70% of the existing and 97% of the planned units are within 100 miles of at least one candidate deep geologic storage reservoir. As a percent of the total CO2 emissions from these facilities, 92% of the exiting units CO2 and 97% of the planned units CO2 emissions are accounted for by facilities that are within 100 miles of at least one potential CO2 storage reservoir.

Dahowski, Robert T.; Dooley, James J.

2008-09-18T23:59:59.000Z

372

Processing dipole acoustic logging data to image fracture network in shale gas reservoirs  

Science Conference Proceedings (OSTI)

A recent advance in borehole remote acoustic reflection imaging is the utilization of a dipole acoustic system in a borehole to emit and receive elastic waves to and from a remote geologic reflector in formation. An important application of this new technique is the delineation of fracture network in shale gas reservoirs

Zhuang Chunxi; Su Yuanda; Tang Xiaoming

2012-01-01T23:59:59.000Z

373

Natural and industrial analogues for leakage of CO2 from storagereservoirs: identification of features, events, and processes and lessonslearned  

SciTech Connect

The injection and storage of anthropogenic CO2 in deepgeologic formations is a potentially feasible strategy to reduce CO2emissions and atmospheric concentrations. While the purpose of geologiccarbon storage is to trap CO2 underground, CO2 could migrate away fromthe storage site into the shallow subsurface and atmosphere if permeablepathways such as well bores or faults are present. Large-magnitudereleases of CO2 have occurred naturally from geologic reservoirs innumerous volcanic, geothermal, and sedimentary basin settings. Carbondioxide and natural gas have also been released from geologic CO2reservoirs and natural gas storage facilities, respectively, due toinfluences such as well defects and injection/withdrawal processes. Thesesystems serve as natural and industrial analogues for the potentialrelease of CO2 from geologic storage reservoirs and provide importantinformation about the key features, events, and processes (FEPs) that areassociated with releases, as well as the health, safety, andenvironmental consequences of releases and mitigation efforts that can beapplied. We describe a range of natural releases of CO2 and industrialreleases of CO2 and natural gas in the context of these characteristics.Based on this analysis, several key conclusions can be drawn, and lessonscan be learned for geologic carbon storage. First, CO2 can bothaccumulate beneath, and be released from, primary and secondaryreservoirs with capping units located at a wide range of depths. Bothprimary and secondary reservoir entrapments for CO2 should therefore bewell characterized at storage sites. Second, many natural releases of CO2have been correlated with a specific event that triggered the release,such as magmatic fluid intrusion or seismic activity. The potential forprocesses that could cause geomechanical damage to sealing cap rocks andtrigger the release of CO2 from a storage reservoir should be evaluated.Third, unsealed fault and fracture zones may act as fast and directconduits for CO2 flow from depth to the surface. Risk assessment shouldtherefore emphasize determining the potential for and nature of CO2migration along these structures. Fourth, wells that are structurallyunsound have the potential to rapidly release large quantities of CO2 tothe atmosphere. Risk assessment should therefore be focused on thepotential for both active and abandoned wells at storage sites totransport CO2 to the surface, particularly at sites with depleted oil orgas reservoirs where wellsare abundant. Fifth, the style of CO2 releaseat the surface varies widely between and within different leakage sites.In rare circumstances, the release of CO2 can be a self-enhancing and/oreruptive process; this possibility should be assessed in the case of CO2leakage from storage reservoirs. Sixth, the hazard to human health hasbeen small in most cases of large surface releases of CO2. This could bedue to implementation of public education and CO2 monitoring programs;these programs should therefore be employed to minimize potential health,safety, and environmental effects associated with CO2 leakage. Finally,while changes in groundwater chemistry were related to CO2 leakage due toacidification and interaction with host rocks along flow paths, watersremained potable in most cases. Groundwaters should be monitored forchanges that may be associated with storage reservoirleakage.

Lewicki, Jennifer L.; Birkholzer, Jens; Tsang, Chin-Fu

2006-02-28T23:59:59.000Z

374

Well Productivity in Gas-Condensate and Volatile Oil Reservoirs:  

E-Print Network (OSTI)

Wells in gas condensate reservoirs usually exhibit complex behaviours due to condensate deposit as the bottomhole pressure drops below the dew point. The formation of this liquid saturation can lead to a severe loss of well productivity and therefore lower gas recovery. A similar behaviour is observed in volatile oil reservoirs below the bubble point. Understanding these behaviours and extracting values of controlling parameters is necessary to evaluate well potential and design effective programmes to improve productivity. The Centre of Petroleum Studies at Imperial College London has been involved in research in these areas since 1997, sponsored mainly by consortia of oil companies. Results from this work have already greatly improved the understanding of well behaviour in gas condensate and volatile oil reservoirs and the ability to interpret well tests in such reservoirs. Work to-date has focused on vertical and horizontal wells in sandstone reservoirs. Much work remains to understand the behaviours of fractured wells and wells in naturally fractured reservoirs. The objective of this proposal is to complete the work performed to-date in sandstone reservoirs and to extend it to new well and reservoir characteristics, in order to develop a better understanding of near-wellbore effects in gas condensate and volatile oil reservoirs from well testing, and to use this understanding to develop new methods for predicting and improving well productivity in such reservoirs. The work will be performed by staff, MSc and PhD students from the Centre for Petroleum Studies at Imperial College, with input and guidance from industry partners.

Prof A. C. Gringarten

2004-01-01T23:59:59.000Z

375

Stress, seismicity and structure of shallow oil reservoirs of Clinton County, Kentucky. Final report  

SciTech Connect

Between 1993 and 1995 geophysicists of the Los Alamos National Laboratory, in a project funded by the US Department of Energy, conducted extensive microseismic monitoring of oil production in the recently discovered High Bridge pools of Clinton County and were able to acquire abundant, high-quality data in the northern of the two pools. This investigation provided both three-dimensional spatial and kinetic data relating to the High Bridge fracture system that previously had not been available. Funded in part by the Los Alamos National Laboratory, the Kentucky Geological Survey committed to develop a geological interpretation of these geophysical results, that would be of practical benefit to future oils exploration. This publication is a summary of the results of that project. Contents include the following: introduction; discovery and development; regional geology; fractured reservoir geology; oil migration and entrapment; subsurface stress; induced seismicity; structural geology; references; and appendices.

Hamilton-Smith, T. [Kentucky Geological Survey, Lexington, KY (United States)

1995-12-12T23:59:59.000Z

376

Application of advanced reservoir characterization, simulation, and production optimization strategies to maximize recovery in slope and basin clastic reservoirs, West Texas (Delaware Basin). Quarterly report, October 1 - December 31, 1996  

SciTech Connect

The objective of this project is 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. Project objectives are divided into two major phases. The objectives of the reservoir characterization phase of the project are to provide a detailed understanding of the architecture and heterogeneity of two fields, the Ford Geraldine unit and Ford West field, which produce from the Bell Canyon and Cherry Canyon Formations, respectively, of the Delaware Mountain Group and to compare Bell Canyon and Cherry Canyon reservoirs. Reservoir characterization will utilize 3-D seismic data, high-resolution sequence stratigraphy, subsurface field studies, outcrop characterization, and other techniques. Once the reservoir-characterization study of both fields is completed, a pilot area of approximately 1 mi{sup 2} in one of the fields will be chosen for reservoir simulation. The objectives of the implementation phase of the project are to (1) apply the knowledge gained from reservoir characterization and simulation studies to increase recovery from the pilot area, (2) demonstrate that economically significant unrecovered oil remains in geologically resolvable untapped compartments, and (3) test the accuracy of reservoir characterization and flow simulation as predictive tools in resource preservation of mature fields. A geologically designed, enhanced-recovery program (CO{sub 2} flood, waterflood, or polymer flood) and well-completion program will be developed, and one to three infill wells will be drilled and cored. Technical progress is summarized for: geophysical characterization; reservoir characterization; outcrop characterization; and recovery technology identification and analysis.

Dutton, S.P.

1997-01-01T23:59:59.000Z

377

Application of advanced reservoir characterization, simulation, and production optimization strategies to maximize recovery in slope and basin clastic reservoirs, West Texas (Delaware Basin). Quarterly report, April 1,1996 - June 30, 1996  

Science Conference Proceedings (OSTI)

The objective of this project is 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. Project objectives are divided into two major phases. The objectives of the reservoir characterization phase of the project are to provide a detailed understanding of the architecture and heterogeneity of two fields, the Ford Geraldine unit and Ford West field, which produce from the Bell Canyon and Cherry Canyon Formations, respectively, of the Delaware Mountain Group and to compare Bell Canyon and Cherry Canyon reservoirs. Reservoir characterization will utilize 3-D seismic data, high-resolution sequence stratigraphy, subsurface field studies, outcrop characterization, and other techniques. Once the reservoir- characterization study of both fields is completed, a pilot area of approximately 1 mi{sup 2} in one of the fields will be chosen for reservoir simulation. The objectives of the implementation phase of the project are to (1) apply the knowledge gained from reservoir characterization and simulation studies to increase recovery from the pilot area, (2) demonstrate that economically significant unrecovered oil remains in geologically resolvable untapped compartments, and (3) test the accuracy of reservoir characterization and flow simulation as predictive tools in resource preservation of mature fields. A geologically designed, enhanced-recovery program (CO{sub 2} flood, waterflood, or polymer flood) and well-completion program will be developed, and one to three infill wells will be drilled and cored. Progress to date is summarized for reservoir characterization.

Dutton, S.P.

1996-07-01T23:59:59.000Z

378

Developing a geoscience knowledge framework for a national geological survey organisation  

Science Conference Proceedings (OSTI)

Geological survey organisations (GSOs) are established by most nations to provide a geoscience knowledge base for effective decision-making on mitigating the impacts of natural hazards and global change, and on sustainable management of natural resources. ... Keywords: 3D models, Cyber-infrastructure, Geological mapping, Knowledge management, Ontology

Andrew S. Howard; Bill Hatton; Femke Reitsma; Ken I. G. Lawrie

2009-04-01T23:59:59.000Z

379

Integrated Reservoir Characterization: Offshore Louisiana, Grand Isle Blocks 32 & 33  

E-Print Network (OSTI)

This thesis integrated geology, geophysics, and petroleum engineering data to build a detailed reservoir characterization models for three gas pay sands in the Grand Isle 33 & 43 fields, offshore Louisiana. The reservoirs are Late Miocene in age and include the upper (PM), middle (QH), and lower (RD) sands. The reservoir models address the stratigraphy of the upper (PM) sand and help delineate the lower (RD) reservoir. In addition, this research addresses the partially depleted QH-2 reservoir compartment. The detailed models were constructed by integrating seismic, well log, and production data. These detailed models can help locate recoverable oil and gas that has been left behind. The upper PM model further delineated that the PM sand has several areas that are shaled-out effectively creating a flow barrier within reservoir compartments. Due to the barrier in the PM-1 reservoir compartment, an area of potentially recoverable hydrocarbons remains. In Grand Isle 33, the middle QH sand was partially depleted in the QH-2 reservoir compartment by a series of development wells. Bottom hole pressure data from wells in Grand Isle 32 & 33 reveal that the two QH fault compartments are in communication across a leaking fault. Production wells in the QH-1 compartment produced reserves from the QH-2 compartment. The lower RD sand model helped further delineate the reservoir in the RD-2 compartment and show that this compartment has been depleted. The RD model also shows the possible presence of remaining recoverable hydrocarbons in the RD-1 compartment. It is estimated that about 6.7 billion cubic feet of gas might remain within this reservoir waiting to be recovered. A seismic amplitude anomaly response from the QH and RD sands is interpreted to be a lithologic indicator rather than the presence of hydrocarbons. Amplitude response from the PM level appears to be below the resolution of the seismic data. A synthetic seismogram model was generated to represent the PM and surrounding sands. This model shows that by increasing the frequency of the seismic data from 20 Hz to a dominant frequency of 30 Hz that the PM and surrounding sands could be seismically resolvable. Also the PM-1 compartment has possible recoverable hydrocarbons of 1.5 billion cubic feet of gas remaining.

Casey, Michael Chase

2011-05-01T23:59:59.000Z

380

Increasing Heavy Oil Reserves in the Wilmington Oil Field Through Advanced Reservoir Characterization and Thermal Production Technologies  

SciTech Connect

The project involves improving thermal recovery techniques in a slope and basin clastic (SBC) reservoir in the Wilmington field, Los Angeles Co., Calif. using advanced reservoir characterization and thermal production technologies. The existing steamflood in the Tar zone of Fault Block (FB) 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 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 a 2100 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.

Scott Hara

1998-03-03T23:59:59.000Z

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381

Increasing Heavy Oil Reserves in the Wilmington Oil Field Through Advanced Reservoir Characterization and Thermal Production Technologies  

SciTech Connect

The project involves improving thermal recovery techniques in a slope and basin clastic (SBC) reservoir in the Wilmington field, Los Angeles Co., Calif. using advanced reservoir characterization and thermal production technologies. The existing steamflood in the Tar zone of Fault Block (FB) 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 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 a 2100 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. Summary of Technical Progress

Scott Hara

1997-08-08T23:59:59.000Z

382

Increasing Heavy Oil Reservers in the Wilmington Oil field Through Advanced Reservoir Characterization and Thermal Production Technologies  

SciTech Connect

The project involves improving thermal recovery techniques in a slope and basin clastic (SBC) reservoir in the Wilmington field, Los Angeles Co., Calif. using advanced reservoir characterization and thermal production technologies. The existing steamflood in the Tar zone of Fault Block (FB) 11-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 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 a 2100 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.

Hara, Scott [Tidelands Oil Production Co., Long Beach, CA (United States)

1997-05-05T23:59:59.000Z

383

Revitalizing a mature oil play: Strategies for finding and producing oil in Frio Fluvial-Deltaic Sandstone reservoirs of South Texas  

Science Conference Proceedings (OSTI)

Domestic fluvial-dominated deltaic (FDD) reservoirs contain more than 30 Billion barrels (Bbbl) of remaining oil, more than any other type of reservoir, approximately one-third of which is in danger of permanent loss through premature field abandonments. The U.S. Department of Energy has placed its highest priority on increasing near-term recovery from FDD reservoirs in order to prevent abandonment of this important strategic resource. To aid in this effort, the Bureau of Economic Geology, The University of Texas at Austin, began a 46-month project in October, 1992, to develop and demonstrate advanced methods of reservoir characterization that would more accurately locate remaining volumes of mobile oil that could then be recovered by recompleting existing wells or drilling geologically targeted infill. wells. Reservoirs in two fields within the Frio Fluvial-Deltaic Sandstone (Vicksburg Fault Zone) oil play of South Texas, a mature play which still contains 1.6 Bbbl of mobile oil after producing 1 Bbbl over four decades, were selected as laboratories for developing and testing reservoir characterization techniques. Advanced methods in geology, geophysics, petrophysics, and engineering were integrated to (1) identify probable reservoir architecture and heterogeneity, (2) determine past fluid-flow history, (3) integrate fluid-flow history with reservoir architecture to identify untapped, incompletely drained, and new pool compartments, and (4) identify specific opportunities for near-term reserve growth. To facilitate the success of operators in applying these methods in the Frio play, geologic and reservoir engineering characteristics of all major reservoirs in the play were documented and statistically analyzed. A quantitative quick-look methodology was developed to prioritize reservoirs in terms of reserve-growth potential.

Knox, P.R.; Holtz, M.H.; McRae, L.E. [and others

1996-09-01T23:59:59.000Z

384

Reservoir simulation and geochemical study of Cerro Prieto I wells  

DOE Green Energy (OSTI)

Combined reservoir simulation and geochemical data analysis are used to investigate the effects of recharge and other reservoir processes occurring in the western part of the Cerro Prieto, Mexico, geothermal field (i.e., Cerro Prieto I area). Enthalpy-based temperatures and bottomhole temperatures are calculated based on simplified models of the system, considering different reservoir boundary conditions and zones of contrasting initial temperatures and reservoir properties. By matching the computed trends with geothermometer-based temperature and enthalpy histories of producing wells, the main processes active in the western area of Cerro Prieto are identified. This part of the geothermal system is strongly influenced by nearby groundwater aquifers; cooler waters readily recharge the reservoirs. In response to exploitation, the natural influx of cold water into the shallower alpha reservoir is mainly from the west and down Fault L, while the recharge to the deeper beta reservoir in this part of the field, seems to be only lateral, from the west and possibly south. 11 refs., 12 figs.

Lippmann, M.J. (Lawrence Berkeley Lab., CA (USA)); Truesdell, A.H. (Geological Survey, Menlo Park, CA (USA))

1990-03-01T23:59:59.000Z

385

The Cove Fort-Sulphurdale KGRA, a geologic and geophysical case study  

DOE Green Energy (OSTI)

Geological, geochemical and geophysical data are presented for one of the major geothermal systems in the western United States. Regional data indicate major tectonic structures which are still active and provide the conduits for the geothermal system. Detailed geologic mapping has defined major glide blocks of Tertiary volcanics which moved down from the Tushar Mountains and locally act as a leaky cap to portions of the presently known geothermal system. Mapping and geochemical studies indicate three periods of mineralization have affected the area, two of which are unrelated to the present geothermal activity. The geologic relationships demonstrate that the major structures have been opened repeatedly since the Tertiary. Gravity and magnetic data are useful in defining major structures beneath alluvium and basalt cover, and indicate the importance of the Cove Fort-Beaver graben and the Cove Creek fault in localizing the geothermal reservoir. These structures and a high level of microearthquake activity also suggest other target areas within the larger thermal anomaly. Electrical resistivity surveys and thermal gradient holes both contribute to the delineation of the known reservoir. Deep exploration wells which test the reservoir recorded maximum temperatures of 178 C and almost isothermal behavior beginning at 700 to 1000 m and continuing to a depth of 1800 m. Costly drilling, high corrosion rates and low reservoir pressure coupled with the relatively low reservoir temperatures have led to the conclusion that the reservoir is not economic for electric power production at present. Plans are underway to utilize the moderate-temperature fluids for agribusiness, and exploration continues for a deep high-temperature reservoir.

Ross, Howard P.; Moore, Joseph N.; Christensen, Odin D.

1982-09-01T23:59:59.000Z

386

Best Practice Guidelines for Geologic Storage of Carbon Dioxide: Geologic Storage Options, Site Evaluation, and Monitoring/Mitigatio n  

Science Conference Proceedings (OSTI)

The purpose of this report is to set forth a set of "best practices" that support long-term, secure storage of captured carbon dioxide (CO2). For each of a suite of geologic storage options, the report establishes background and basic concepts, defines site selection criteria and procedures, and sets forth monitoring and mitigation options. The initial suite of geologic CO2 storage options to be addressed includes saline aquifers, depleted oil fields, depleted natural gas fields, and deep unmineable coal...

2004-12-22T23:59:59.000Z

387

Identification and evaluation of fluvial-dominated deltaic (class 1 oil) reservoirs in Oklahoma. Quarterly technical progress report, April 1, 1994--June 30, 1994  

Science Conference Proceedings (OSTI)

The Oklahoma Geological Survey (OGS), the Geological Information Systems department, and the School of Petroleum and Geological Engineering at the University of Oklahoma are engaging in a program to identify and address Oklahoma`s oil recovery opportunities in fluvial-dominated deltaic (FDD) reservoirs. This program includes the systematic and comprehensive collection and evaluation of information on all of Oklahoma`s FDD reservoirs and the recovery technologies that have been (or could be) applied to those reservoirs with commercial success. This data collection and evaluation effort will be the foundation for an aggressive, multifaceted technology transfer program that is designed to support all of Oklahoma`s oil industry, with particular emphasis on smaller companies and independent operators in their attempts to maximize the economic producibility of FDD reservoirs.

Mankin, C.J. [Oklahoma Geological Survey, Norman, OK (United States); Banken, M.K. [Oklahoma Univ., Norman, OK (United States)

1994-12-08T23:59:59.000Z

388

Integration of the geological/engineering model with production performance for Patrick Draw Field, Wyoming  

SciTech Connect

The NIPER Reservoir Assessment and Characterization Research Program incorporates elements of the near-term, mid-term and long-term objectives of the National Energy Strategy-Advanced Oil Recovery Program. The interdisciplinary NIPER team focuses on barrier island reservoirs, a high priority class of reservoirs, that contains large amounts of remaining oil in place located in mature fields with a high number of shut-in and abandoned wells. The project objectives are to: (1) identify heterogeneities that influence the movement and trapping of reservoir fluids in two examples of shoreline barrier reservoirs (Patrick Draw Field, WY and Bell Creek Field, MT); (2) develop geological and engineering reservoir characterization methods to quantify reservoir architecture and predict mobile oil saturation distribution for application of targeted infill drilling and enhanced oil recovery (EOR) processes; and (3) summarize reservoir and production characteristics of shoreline barrier reservoirs to determine similarities and differences. The major findings of the research include: (1) hydrogeochemical analytical techniques were demonstrated to be an inexpensive reservoir characterization tool that provides information on reservoir architecture and compartmentalization; (2) the formation water salinity in Patrick Draw Field varies widely across the field and can result in a 5 to 12% error in saturation values calculated from wireline logs if the salinity variations and corresponding resistivity values are not accounted for; and (3) an analysis of the enhanced oil recovery (EOR) potential of Patrick Draw Field indicates that CO{sub 2} flooding in the Monell Unit and horizontal drilling in the Arch Unit are potential methods to recover additional oil from the field.

Jackson, S.

1993-03-01T23:59:59.000Z

389

Integration of the geological/engineering model with production performance for Patrick Draw Field, Wyoming  

SciTech Connect

The NIPER Reservoir Assessment and Characterization Research Program incorporates elements of the near-term, mid-term and long-term objectives of the National Energy Strategy-Advanced Oil Recovery Program. The interdisciplinary NIPER team focuses on barrier island reservoirs, a high priority class of reservoirs, that contains large amounts of remaining oil in place located in mature fields with a high number of shut-in and abandoned wells. The project objectives are to: (1) identify heterogeneities that influence the movement and trapping of reservoir fluids in two examples of shoreline barrier reservoirs (Patrick Draw Field, WY and Bell Creek Field, MT); (2) develop geological and engineering reservoir characterization methods to quantify reservoir architecture and predict mobile oil saturation distribution for application of targeted infill drilling and enhanced oil recovery (EOR) processes; and (3) summarize reservoir and production characteristics of shoreline barrier reservoirs to determine similarities and differences. The major findings of the research include: (1) hydrogeochemical analytical techniques were demonstrated to be an inexpensive reservoir characterization tool that provides information on reservoir architecture and compartmentalization; (2) the formation water salinity in Patrick Draw Field varies widely across the field and can result in a 5 to 12% error in saturation values calculated from wireline logs if the salinity variations and corresponding resistivity values are not accounted for; and (3) an analysis of the enhanced oil recovery (EOR) potential of Patrick Draw Field indicates that CO[sub 2] flooding in the Monell Unit and horizontal drilling in the Arch Unit are potential methods to recover additional oil from the field.

Jackson, S.

1993-03-01T23:59:59.000Z

390

Application of artificial intelligence to reservoir characterization: An interdisciplinary approach. [Quarterly report], January 1--March 31, 1995  

SciTech Connect

This basis search is to apply novel techniques from Artificial Intelligence (AI) and Expert Systems in capturing, integrating and articulating key knowledge from geology, geostatistics, and petroleum engineering to develop accurate descriptions of petroleum reservoirs. The ultimate goal is to design and implement a single powerful expert system for use by small producers and independents to efficiently exploit reservoirs. The overall project plan to design the system to create integrated reservoir description begins by initially developing an AI-based methodology for producing large-scale reservoir descriptions generated interactively from geology and well test data. Parallel to this task is a second task that develops an AI-based methodology that uses facies-biased information to generate small-scale descriptions of reservoir properties such as permeability and porosity. The third task involves consolidation and integration of the large-scale and small-scale methodologies to produce reservoir descriptions honoring all the available data. The final task will be technology transfer. With this plan, we have carefully allocated and sequenced the activities involved in each of the tasks to promote concurrent progress towards the research objectives. The results of the integration are not merely limited to obtaining better characterizations of individual reservoirs. They have the potential to significantly impact and advance the discipline of reservoir characterization itself.

Kelkar, B.G.; Kerr, D.R.; Thompson, L.G.; Shenoi, S.

1995-07-01T23:59:59.000Z

391

Multiscale Reservoir Simulation: Layer Design, Full Field Pseudoization and Near Well Modeling  

E-Print Network (OSTI)

In the past decades, considerable effort has been put into developing high resolution geological models for oil and gas reservoirs. Although the growth of computational power is rapid, the static model size still exceeds the model size for routine reservoir simulation. We develop and apply a variety of grid coarsening and refinement algorithms and single and multiphase upscaling approaches, applied to tight gas and conventional reservoir models. The proposed research is organized into three areas. First the upgridding of detailed three dimensional geologic models is studied. We propose an improved layer design algorithm with considerations of accuracy and efficiency. This involves developing measures of reservoir heterogeneity and using these measures to design an optimal grouping of geologic model layers for flow simulation. The optimal design is shown to be a tradeoff between the desire to preserve the reservoir heterogeneity and a desire to minimize the simulation time. The statistical analysis is validated by comparison with flow simulation results. Accurate upgridding/upscaling of single-phase parameters is necessary. However, it does not always satisfy the accuracy requirements, especially for the model which is aggressively coarsened. We introduce a pseudoization method with total mobility and effective fractional flow as the major targets. This pseudoization method helps to push upgridding/coarsening degree to the limit but still be able to reproduce the fine scale field performance. In practice, it is common to not use a different set of pseudos for every coarse cell; only a limited number of pseudo functions should be generated for different rock types or geological zones. For similar well patterns and well control conditions, applying pseudo is able to reproduce the fine scale performance for different simulation runs. This is the second proposed research area. Finally, it is necessary to increase flow resolution for precise field history matching and forecasting. This has received increasing attention, especially when studying hydraulically fractured wells in unconventional reservoirs. We propose a multiscale reservoir simulation model combining local grid refinement (LGR) and pillar-based upscaling for tight gas reservoir performance prediction. Pillar-based coarsening away from the wells is designed for tight gas reservoirs. It compensates for the extra computational cost from LGR, which is used to represent hydraulic fractures. Overall reservoir performances, including the accuracy and efficiency, are evaluated.

Du, Song

2012-12-01T23:59:59.000Z

392

HIGH-PRESSURE AIR INJECTION: APPLICATION IN A FRACTURED AND KARSTED DOLOMITE RESERVOIR  

SciTech Connect

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.

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

2003-12-10T23:59:59.000Z

393

Using microstructure observations to quantify fracture properties and improve reservoir simulations. Final report, September 1998  

Science Conference Proceedings (OSTI)

The research for this project provides new technology to understand and successfully characterize, predict, and simulate reservoir-scale fractures. Such fractures have worldwide importance because of their influence on successful extraction of resources. The scope of this project includes creation and testing of new methods to measure, interpret, and simulate reservoir fractures that overcome the challenge of inadequate sampling. The key to these methods is the use of microstructures as guides to the attributes of the large fractures that control reservoir behavior. One accomplishment of the project research is a demonstration that these microstructures can be reliably and inexpensively sampled. Specific goals of this project were to: create and test new methods of measuring attributes of reservoir-scale fractures, particularly as fluid conduits, and test the methods on samples from reservoirs; extrapolate structural attributes to the reservoir scale through rigorous mathematical techniques and help build accurate and useful 3-D models of the interwell region; and design new ways to incorporate geological and geophysical information into reservoir simulation and verify the accuracy by comparison with production data. New analytical methods developed in the project are leading to a more realistic characterization of fractured reservoir rocks. Testing diagnostic and predictive approaches was an integral part of the research, and several tests were successfully completed.

Laubach, S.E.; Marrett, R.; Rossen, W.; Olson, J.; Lake, L.; Ortega, O.; Gu, Y.; Reed, R.

1999-01-01T23:59:59.000Z

394

Evaluating Potential for Large Releases from CO2 StorageReservoirs: Analogs, Scenarios, and Modeling Needs  

SciTech Connect

While the purpose of geologic storage of CO{sub 2} in deep saline formations is to trap greenhouse gases underground, the potential exists for CO{sub 2} to escape from the target reservoir, migrate upward along permeable pathways, and discharge at the land surface. Such discharge is not necessarily a serious concern, as CO{sub 2} is a naturally abundant and relatively benign gas in low concentrations. However, there is a potential risk to health, safety and environment (HSE) in the event that large localized fluxes of CO{sub 2} were to occur at the land surface, especially where CO{sub 2} could accumulate. In this paper, we develop possible scenarios for large CO{sub 2} fluxes based on the analysis of natural analogues, where large releases of gas have been observed. We are particularly interested in scenarios which could generate sudden, possibly self-enhancing, or even eruptive release events. The probability for such events may be low, but the circumstances under which they might occur and potential consequences need to be evaluated in order to design appropriate site selection and risk management strategies. Numerical modeling of hypothetical test cases is needed to determine critical conditions for such events, to evaluate whether such conditions may be possible at designated storage sites, and, if applicable, to evaluate the potential HSE impacts of such events and design appropriate mitigation strategies.

Birkholzer, Jens; Pruess, Karsten; Lewicki, Jennifer; Tsang,Chin-Fu; Karimjee, Anhar

2005-09-19T23:59:59.000Z

395

Innovative MIOR Process Utilizing Indigenous Reservoir Constituents  

Science Conference Proceedings (OSTI)

This research program is directed at improving the knowledge of reservoir ecology and developing practical microbial solutions for improving oil production. The goal is to identify 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 is underway. Microbial cultures have been 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 with cultures and conditions representative of oil reservoirs. Field pilot studies are underway.

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

2003-03-31T23:59:59.000Z

396

Use Of Electrical Surveys For Geothermal Reservoir Characterization-  

Open Energy Info (EERE)

Use Of Electrical Surveys For Geothermal Reservoir Characterization- Use Of Electrical Surveys For Geothermal Reservoir Characterization- Beowawe Geothermal Field Jump to: navigation, search GEOTHERMAL ENERGYGeothermal Home Conference Paper: Use Of Electrical Surveys For Geothermal Reservoir Characterization- Beowawe Geothermal Field Details Activities (4) Areas (1) Regions (0) Abstract: The STAR geothermal reservoir simulator was used to model the natural state of the Beowawe geothermal field, and to compute the subsurface distributions of temperature and salinity which were in turn employed to calculate pore-fluid resistivity. Archie's law, which relates formation resistivity to porosity and pore-fluid resistivity, was adopted to infer formation resistivity distribution. Subsequently, DC, MT and SP postprocessors were used to compute the expected response corresponding to

397

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

SciTech Connect

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.

Riley, Ronald; Wicks, John; Perry, Christopher

2009-12-30T23:59:59.000Z

398

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

Science Conference Proceedings (OSTI)

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.

Ronald Riley; John Wicks; Christopher Perry

2009-12-30T23:59:59.000Z

399

Reservoir engineering report for the magma-SDG and E geothermal experimental site near the Salton Sea, California  

DOE Green Energy (OSTI)

A description of the Salton Sea geothermal reservoir is given and includes approximate fault locations, geology (lithology), temperatures, and estimates of the extent of the reservoir. The reservoir's temperatures and chemical composition are also reviewed. The flow characteristics are discussed after analyses of drillstem tests and extended well tests. The field production, reserves and depletion are estimated, and the effects of fractures on flow and depletion are discussed. The reservoir is believed to be separated into an ''upper'' and ''lower'' portion by a relatively thick and continuous shale layer. The upper reservoir is highly porous, with high permeability and productivity. The lower reservoir is at least twice as large as the upper but has much lower storativity and permeability in the rock matrix. The lower reservoir may be highly fractured, and its temperatures and dissolved solids are greater than those of the upper reservoir. The proven reserves of heat in the upper reservoir are about /sup 1///sub 4/ GW.yr (in the fluid) and /sup 1///sub 3/ GW.yr (in the rock). In the lower reservoir the proven reserves of heat are 5/sup 3///sub 4/ GW.yr (in the fluid) and 17 GW.yr (in the rock). Unproven reserves greatly exceed these numbers. Injection tests following well completion imply that hydraulic fracturing has taken place in two of the SDG and E wells and at least one other well nearby.

Schroeder, R.C.

1976-07-12T23:59:59.000Z

400

NETL: Oil & Natural Gas Technologies Reference Shelf - Presentation...  

NLE Websites -- All DOE Office Websites (Extended Search)

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