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Title: A combined saline formation and gas reservoir CO2 injection pilotin Northern California

Abstract

A geologic sequestration pilot in the Thornton gas field in Northern California, USA involves injection of up to 4000 tons of CO{sub 2} into a stacked gas and saline formation reservoir. Lawrence Berkeley National Laboratory (LBNL) is leading the pilot test in collaboration with Rosetta Resources, Inc. and Calpine Corporation under the auspices of the U.S. Department of Energy and California Energy Commission's WESTCARB, Regional Carbon Sequestration Partnership. The goals of the pilot include: (1) Demonstrate the feasibility of CO{sub 2} storage in saline formations representative of major geologic sinks in California; (2) Test the feasibility of Enhanced Gas Recovery associated with the early stages of a CO{sub 2} storage project in a depleting gas field; (3) Obtain site-specific information to improve capacity estimation, risk assessment, and performance prediction; (4) Demonstrate and test methods for monitoring CO{sub 2} storage in saline formations and storage/enhanced recovery projects in gas fields; and (5) Gain experience with regulatory permitting and public outreach associated with CO{sub 2} storage in California. Test design is currently underway and field work begins in August 2006.

Authors:
; ; ; ; ;
Publication Date:
Research Org.:
Ernest Orlando Lawrence Berkeley NationalLaboratory, Berkeley, CA (US)
Sponsoring Org.:
USDOE. Assistant Secretary for Fossil Energy. Office of Coaland Power Systems, National Energy Technologies Laboratory
OSTI Identifier:
900793
Report Number(s):
LBNL-60169
R&D Project: G20901; BnR: AA3010000; TRN: US200711%%613
DOE Contract Number:
DE-AC02-05CH11231
Resource Type:
Conference
Resource Relation:
Conference: 8th International Green House Gas ControlTechnology, Trondheim, Norway, 19-22 June 2006
Country of Publication:
United States
Language:
English
Subject:
54; CAPACITY; CARBON SEQUESTRATION; DESIGN; FORECASTING; MONITORING; NATURAL GAS FIELDS; PERFORMANCE; RISK ASSESSMENT; STORAGE

Citation Formats

Trautz, Robert, Myer, Larry, Benson, Sally, Oldenburg, Curt, Daley, Thomas, and Seeman, Ed. A combined saline formation and gas reservoir CO2 injection pilotin Northern California. United States: N. p., 2006. Web.
Trautz, Robert, Myer, Larry, Benson, Sally, Oldenburg, Curt, Daley, Thomas, & Seeman, Ed. A combined saline formation and gas reservoir CO2 injection pilotin Northern California. United States.
Trautz, Robert, Myer, Larry, Benson, Sally, Oldenburg, Curt, Daley, Thomas, and Seeman, Ed. Fri . "A combined saline formation and gas reservoir CO2 injection pilotin Northern California". United States. doi:. https://www.osti.gov/servlets/purl/900793.
@article{osti_900793,
title = {A combined saline formation and gas reservoir CO2 injection pilotin Northern California},
author = {Trautz, Robert and Myer, Larry and Benson, Sally and Oldenburg, Curt and Daley, Thomas and Seeman, Ed},
abstractNote = {A geologic sequestration pilot in the Thornton gas field in Northern California, USA involves injection of up to 4000 tons of CO{sub 2} into a stacked gas and saline formation reservoir. Lawrence Berkeley National Laboratory (LBNL) is leading the pilot test in collaboration with Rosetta Resources, Inc. and Calpine Corporation under the auspices of the U.S. Department of Energy and California Energy Commission's WESTCARB, Regional Carbon Sequestration Partnership. The goals of the pilot include: (1) Demonstrate the feasibility of CO{sub 2} storage in saline formations representative of major geologic sinks in California; (2) Test the feasibility of Enhanced Gas Recovery associated with the early stages of a CO{sub 2} storage project in a depleting gas field; (3) Obtain site-specific information to improve capacity estimation, risk assessment, and performance prediction; (4) Demonstrate and test methods for monitoring CO{sub 2} storage in saline formations and storage/enhanced recovery projects in gas fields; and (5) Gain experience with regulatory permitting and public outreach associated with CO{sub 2} storage in California. Test design is currently underway and field work begins in August 2006.},
doi = {},
journal = {},
number = ,
volume = ,
place = {United States},
year = {Fri Apr 28 00:00:00 EDT 2006},
month = {Fri Apr 28 00:00:00 EDT 2006}
}

Conference:
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  • The long-term behavior of a CO{sub 2} plume injected into a deep saline formation is investigated, focusing on mechanisms that lead to plume stabilization. Key measures are plume migration distance and the time evolution of CO{sub 2} phase-partitioning, which are examined by developing a numerical model of the subsurface at a proposed power plant with CO{sub 2} capture in the San Joaquin Valley, California, where a large-volume pilot test of CO{sub 2} injection will be conducted. The numerical model simulates a four-year CO{sub 2} injection period and the subsequent evolution of the CO{sub 2} plume until it stabilizes. Sensitivity studiesmore » are carried out to investigate the effect of poorly constrained model parameters permeability, permeability anisotropy, and residual gas saturation.« less
  • At Buena Vista field, California, 120 ft of post-steamflood core, spanning the middle Pliocene Wilhelm Member of the Etchegoin Formation, was taken to assess the influence of stratigraphy on light-oil steamflood (LOSF) processes and to determine what steam-rock reactions occurred and how these affected reservoir properties. High-quality steam (600F (300C)) had been injected ({approximately}1,700 psi) into mixed tidal flat and estuarine facies in an injector well located 55 ft from the cored well. Over a period of 20 months, steam rapidly channeled through a thin ({approximately}7 ft), relatively permeable (1-1,000 md), flaser-bedded sandstone unit. Conductive heating above this permeable unitmore » produced, in the vicinity of the cored well, a 35-ft steam-swept zone (oil saturation = 0), overlain by a 29-ft steam-affected zone in which oil saturation had been reduced to 13%, far below the presteam saturation of 30%. Steam-induced alteration ('artificial diagenesis') of the clay-rich reservoir rock was recognized using SEM, petrography, and X-ray diffraction. Salient dissolution effects were the complete to partial removal of siliceous microfossils, Fe-dolomite, volcanic rock fragments, and labile heavy minerals. The artificial diagenetic effects are first encountered in the basal 6 ft of the 29-ft steam-affected zone. Based on the distribution of the authigenic phases, the authors conclude that the reactions took place, or were at least initiated, in the steam condensate bank ahead of the advancing steam front. Although these changes presumably reduced permeability, the steamflood process was effective in reducing oil saturation to zero in the steam-contacted portion of the reservoir.« less
  • The Temblor Zone II reservoir consists of intervals of movable oil associated with intervals of high gas saturation or desaturated intervals. Natural gas injection into these desaturated intervals, using tritium and krypton as radioactive tracers has served to determine reservoir continuity. In these example cases, the desaturated intervals contained nearly all carbon dioxide gas. The injection tests also have furnished data concerning the nature and distribution of desaturated intervals in an unconsolidated sand reservoir with permeabilities of 300 to 500 md and porosity of 26% having 21/sup 0/ API gravity oil with a viscosity of 25 cp at reservoir temperature.more » It can be concluded from these tests that (1) the injection of radioactive gas into reservoirs having oil desaturation can be used to map continuity, (2) gas-oil interfaces found in some gravity drainage reservoirs deviate from the horizontal, and (3) the gas overlying the movable oil will likely influence supplemental recovery projects by acting as a thief zone for injected water.« less
  • Injection of CO{sub 2} into saline aquifers may cause formation dry-out and precipitation of salt near the injection well, which may reduce formation porosity, permeability, and injectivity. This paper uses numerical simulation to explore the role of different processes and parameters in the salt precipitation process and to examine injection strategies that could mitigate the effects. The main physical mechanisms affecting the dry-out and salt precipitation process include (1) displacement of brine away from the injection well by injected CO{sub 2}, (2) dissolution (evaporation) of brine into the flowing CO{sub 2} stream, (3) upflow of CO{sub 2} due to gravitymore » effects (buoyancy), (4) backflow of brine toward the injection point due to capillary pressure gradients that oppose the pressure gradient in the CO{sub 2}-rich ('gas') phase, and (5) molecular diffusion of dissolved salt. The different mechanisms operate on a range of spatial scales. CO{sub 2} injection at constant rate into a homogeneous reservoir with uniform initial conditions is simulated in 1-D radial geometry, to resolve multiscale processes by taking advantage of the similarity property, i.e., the evolution of system conditions as a function of radial distance R and time t depends only on the similarity variable R{sup 2}/t. Simulations in 2-D vertical cross sections are used to examine the role of gravity effects. We find that counterflow of CO{sub 2} and brine can greatly increase aqueous phase salinity and can promote substantial salt precipitation even in formations with low dissolved solids. Salt precipitation can accentuate effects of gravity override. We find that injecting a slug of fresh water prior to commencement of CO{sub 2} injection can reduce salt precipitation and permeability loss near the injection well.« less
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