PRODUCTS

LIBRARY

Unconventional Resources

Gas Shales

Tight Gas Sands

Coalbed Methane

Enhanced Oil Recovery

Carbon Storage

Gas Storage

Coal-Seq Consortium

Other

 


Gas Shales

Stevens, S.H. and Moodhe, K.; New Bid Round Accelerates Mexico’s Shale Potential, Oil & Gas Journal, p. 39-42, June 6, 2016.

To access this article, please go to http://www.ogj.com/index.html. Subscription fees may apply.

Stevens, S. H., & Moodhe, K. D. (2015, November 18). Evaluation of Mexico’s Shale Oil and Gas Potential. Society of Petroleum Engineers. doi:10.2118/177139-MS

Abstract
Mexico has significant oil and gas resource potential in Jurassic and Cretaceous age shale formations. These shale deposits -- which correlate with productive shale plays in the USA -- appear prospective but are still in the early stage of exploration and thus remain poorly characterized. Early shale exploration wells tested mostly low rates, but a recent oil well made 500 bopd while a shale gas well reached 10.9 MMcfd.

The Mexican government plans to offer shale exploration blocks through an international auction. As part of a multi-client study, the authors have greatly expanded the geologic and reservoir data set we developed during an earlier scoping-level study conducted for the US Energy Information Administration (EIA). The additional geologic data support our initial view that Mexico has some of the largest and best quality shale potential outside the US and Canada. Risked, technically recoverable resources were estimated in the EIA/ARI study at 13.1 BBO of oil and 545 Tcf of natural gas.

Detailed geologic mapping and analysis indicates the two most prospective liquids-rich shale areas in Mexico occur within onshore portions of the Burgos and Tampico-Misantla basins, which have transport infrastructure and well services. Significant potential also exists in the Veracruz, Macuspana, Sabinas, and other onshore basins, but those areas tend to be structurally more complex and/or are mostly in the dry gas window.

The U. Cretaceous Eagle Ford Shale (in the Burgos) and correlative Agua Nueva Formation (in the Tampico-Misantla) have high TOC and brittle carbonate-rich mineralogy, but their net prospective area is reduced due to often shallow burial depth and low thermal maturity. A better target appears to be the U. Jurassic Pimienta and La Casita formations, which can be thick (~200 m), at prospective depth over much larger areas, are in the volatile oil to wet gas windows, and frequently overpressured, although TOC is lower than in the Agua Nueva.

Full paper available https://www.onepetro.org/conference-paper/SPE-177139-MS

Stevens, S. H., Moodhe, K. D., & Kuuskraa, V. A. (2013, October 22). China Shale Gas and Shale Oil Resource Evaluation and Technical Challenges. Society of Petroleum Engineers. doi:10.2118/SPE 165832-MS

Abstract
China has abundant organic-rich source rock shales which are prospective for commercial shale gas/oil development but still in the early phase of evaluation and testing. We analyzed petroleum source rock data published in nearly 400 Chinese language papers to construct a unique GIS data base of shale geologic and reservoir properties throughout the country. We then conducted a comprehensive assessment of the country's shale gas and shale oil resource potential. China's risked technically recoverable resources within high-graded prospective areas are estimated at 1,115 Tcf of shale gas and 32 BBO of shale oil resources (Table 1). Of the dozen onshore sedimentary basins that were assessed, the most prospective are Sichuan, Tarim, Junggar, and Songliao. One of the most intriguing prospects is liquids-rich Permian shale on the structurally simple northwest flank of the Junggar Basin. The Pingdiquan/Lucaogou lacustrine shale is about 250 m thick and 3,500 m deep here. TOC averages 5% and the shale is oil-prone (Ro 0.85%). The area is close to infrastructure.

The Sichuan Basin, industry's primary focus for shale gas, has multiple shale targets but also significant geologic challenges, such as numerous faults (some active), often steep dips, high tectonic stress, slow drilling in hard formations, and high H2S and CO2 in places. Tarim Basin shale targets are mostly too deep (>5 km) apart from uplifts where they may be thin with low TOC. The Songliao Basin has liquids-rich potential in over-pressured and naturally fractured Cretaceous lacustrine shales. However, China's shale oil deposits tend to be waxy and stored mainly in lacustrine-deposited shales, which may be clay-rich and less "frackable” than the low-clay brittle marine shales productive in North America

Full paper available at https://www.onepetro.org.

Stevens, S.H. and Kuuskraa, V.A.; “Gas Shale – 1: Seven Plays Dominate North America”, Oil & Gas Journal, Special Report: Trends in Unconventional Gas, p. 39-49, September 28, 2009.

To access this article, please go to http://www.ogj.com/index.html. Subscription fees may apply.

Kuuskraa, V.A. and Stevens, S.H.; “Gas Shale – 2: Lessons Learned Help Optimize Development”, Oil & Gas Journal, Special Report: Trends in Unconventional Gas, p. 52-57, October 5, 2009.

To access this article, please go to http://www.ogj.com/index.html. Subscription fees may apply.

Stevens, S.H., Godec, M., and Moodhe, K.; “Gas Shale – 3: New Plays Emerge Although Environmental Issues Arise”, Oil & Gas Journal, Special Report: Trends in Unconventional Gas, p. 39-45, October 19, 2009.

To access this article, please go to http://www.ogj.com/index.html. Subscription fees may apply.

Schepers, K. C., Gonzalez, R. J., Koperna, G. J., & Oudinot, A. Y. (2009, January 1). Reservoir Modeling in Support of Shale Gas Exploration. Society of Petroleum Engineers. doi:10.2118/SPE 123057-MS

Abstract
Shale gas and other unconventional gas plays have become an important factor in the United States energy market, and are often referred to as statistical plays due to their high heterogeneity. They present real engineering challenges for characterization and exploitation, and their productivity depends upon an inter-related set of reservoir, completion and production characteristics.

Shale gas plays are generally characterized by low geologic risk and a high commercial risk. Extensive and continuous deposits of tight, usually naturally-fractured shale provide the duality of a potentially-productive reservoir being the hydrocarbon source. Commercial production is a huge unknown in these plays, and reservoir modeling as well as production predictions involve considerable uncertainty. Because of the large number of unknowns, a merely deterministic approach is often incapable of capturing the complete impact of all interdependencies present in a shale gas resource play.

Consequently, one must take into account multiple scenarios to find better exploitation plans. Tools are therefore needed to identify the most important geologic and engineering factors, and to quantify the range of variability in uncertain variables. Reservoir simulation coupled with stochastic methods, i.e., Monte Carlo and geostatistical procedures, have provided excellent means to predict production profiles with a wide variety of reservoir character and producing conditions.

Defining and representing uncertainties with a quantitative understanding of their respective impacts on commercial achievability is crucial to subsequent decisions involving continued investment for commercial purposes.

This paper describes a systematic process employed in the evaluation of a new prospect area (a shale gas play) with very limited available data. In order to properly model the problem with uncertainty, geological and engineering issues were framed within conventional Monte-Carlo procedures and geostatistical characterization algorithms to identify key production parameters so that relevant data can be collected. This process also allows for the investigation of how the combination of a nested natural fracture system, appropriate wellbore design and stimulation are necessary to drive productivity, and provide project results in terms of ranges of outcomes and associated probabilities. Consequently, managers can be in a better position to make informed decisions regarding the uncertainty of such projects.

Full paper available at https://www.onepetro.org.

Kuuskraa, V. A., Koperna, G., Schmoker, J., and Quinn, J.;“Barnett Shale Rising Star in Fort Worth Basin” Oil and Gas Journal, Vol. 96, No. 21, May 25, 1998, pp. 67-76.

To access this article, please go to http://www.ogj.com/index.html. Subscription fees may apply.

Reeves, S. R., Kuuskraa, V. A., and Hill D. G.; “New Basins Invigorate U.S. Gas Shales Play”, Oil and Gas Journal, Vol. 94, No. 4, January 22, 1996, pp. 53-58.

To access this article, please go to http://www.ogj.com/index.html. Subscription fees may apply.

Advanced Resources International, Inc., “Stimulation Technology in the Antrim Shale”, Topical Report, GRI- 94/0101, April, 1994.

Advanced Resources International, Inc., “Evaluation of RA Tracer Surveys and Hydraulic Fracture ID Logs in the Antrim Shale”, Topical Report, GRI-93/0459, November, 1993.

Advanced Resources International, Inc., “Field Projects in the Antrim Shale: The Bagley East Project”, Topical Report, GRI- 92/0419, March, 1993.

Kuuskraa, V. A., Wicks, D. E., and Thurber, J. L.; “Geologic and Reservoir Mechanisms Controlling Gas Recovery From the Antrim Shale”, SPE Annual Technical Conference, SPE No. 24883, pp. 209-224, Washington, D.C., October 4-7, 1992.

Abstract
The Antrim Shale is one of the most active natural gas plays in the U.S., accounting for more than 10% of all gas well completions in 1991. Yet, geologic and production mechanisms of this large, unconventional resource remain poorly understood. Complex reservoir phenomena controlling production include two-phase flow, gas desorption, and fracture permeability. Current operational practice, which relies on gas-assist to lift formation water and reduce bottom-hole pressure, may not optimize well productivity, currently averaging about 85 Mcfd in the basin.

The reservoir processes controlling gas production in the Antrim Shale involve a combination of characteristics typical of three types of unconventional reservoirs: coalbed methane, fractured shales, and tight gas sands. Adsorption, as the primary gas storage mechanism, requires lower downhole operating pressures to achieve gas production. Fracturing of the Antrim, as the primary process controlling natural permeability, requires improved knowledge of fracture density, dimensions, and geometry. Free gas stored in micropores within the shale matrix, similar to right gas sands, requires an understanding of water and gas saturation. This makes the Antrim Shale a '"triple-porosity"' system which requires the development of new reservoir modeling tools to predict well productivity from test and early time production data.

A simulation sensitivity study was conducted on the Antrim Shale using the COMETPC-3D reservoir simulator. This study varied fracture spacing, porosity, sorption time, matrix compressibility and other parameters to identify the most sensitive variables.

Downhole pumps have recently been introduced to more effectively dewater Antrim wells. These pumps can reduce flowing bottom-hole pressure to 50 psi, sufficient to achieve favorable relative permeability and to improve gas desorption. A GRI-funded field project at NOMECO's Bagley East Project which converted a gas-assist Antrim well to downhole mechanical pumping led to a 116% increase in gas production, demonstrating the importance of dewatering and BHP reduction in optimizing Antrim gas production.

Full paper available at https://www.onepetro.org

Salamy, S. P., Aminian, K., Koperna, G. J., Locke, C. D., “Pre- and Post Stimulation Well Test Data Analysis from Horizontal Wells in the Devonian Shale”, SPE No. 23449, presented at the SPE Eastern Regional Meeting, October 22-25, 1991, Lexington, KY.

Abstract
Recent drilling and completion operations have demonstrated the technical and economical successes of horizontal wells over that of vertical wells. The need for horizontal wells was established as a vital production enhancement technique for wells production enhancement technique for wells producing from economically marginal, low producing from economically marginal, low permeable gas formations in the Appalachian Basin permeable gas formations in the Appalachian Basin exhibiting strong permeability anisotropy.

As part of a U.S. Department of Energy (U.S.DOE) funded research project, several horizontal wells were drilled and completed to the Devonian Shale strata in the Appalachian Basin. Production from these wells exhibited high improvement ratios to that from vertical wells; however, to enhance the economics of the horizontal wells, stimulation was indicated. The success of the stimulation techniques and the measure of improvements were determined from production results and/or pressure analyses.

This paper exhibits and summarizes the results of production and pressure buildup data analyses for the production and pressure buildup data analyses for the different horizontal wells. Based on pre- and post-stimulation production and pressure data, various post-stimulation production and pressure data, various well test analysis techniques such as type curves for horizontal gas wells, reservoir simulation, Horner's method, and other applicable techniques are utilized.

Finally, the correlation of production and pressure analysis results helped in the assessment and evaluation of the stimulation techniques.

Full paper available at https://www.onepetro.org.

Salamy, S. P., Aminian, K., Koperna, G. J., Locke, C. D., “Analysis of Well Test Results From Horizontal Gas Shale Wells”, SPE No. 21498, presented at the SPE Gas Technology Symposium, January 22-24, 1991, Houston, TX.

Abstract
Recent drilling and completion operations have demonstrated the technical and economical successes of horizontal wells over that of vertical wells. The need for horizontal wells was established as a vital production enhancement technique for wells production enhancement technique for wells producing from economically marginal, low producing from economically marginal, low permeable gas formations in the Appalachian Basin permeable gas formations in the Appalachian Basin exhibiting strong permeability anisotropy.

As part of a U.S. Department of Energy (U.S.DOE) funded research project, several horizontal wells were drilled and completed to the Devonian Shale strata in the Appalachian Basin. Production from these wells exhibited high improvement ratios to that from vertical wells; however, to enhance the economics of the horizontal wells, stimulation was indicated. The success of the stimulation techniques and the measure of improvements were determined from production results and/or pressure analyses.

This paper exhibits and summarizes the results of production and pressure buildup data analyses for the production and pressure buildup data analyses for the different horizontal wells. Based on pre- and post-stimulation production and pressure data, various post-stimulation production and pressure data, various well test analysis techniques such as type curves for horizontal gas wells, reservoir simulation, Homer's method, and other applicable techniques are utilized.

Finally, the correlation of production and pressure analysis results helped in the assessment and evaluation of the stimulation techniques.

Full paper available at https://www.onepetro.org


Tight Gas Sands

Kuuskraa, V.A., and J. Ammer, 2004. “Tight Gas Sands Development How to Dramatically Improve Recovery Efficiency”, GasTIPS, Winter 2004.

Advanced Resources International, Inc., “Development and Testing of a Restimulation Candidate Selection Methodology for Complex Tight Gas Reservoirs”, Topical Report, GRI-01/0145, July, 2001.

Advanced Resources International, Inc., “Natural Gas Production Enhancement via Restimulation”, Final Report, GRI-01/0144, June, 2001.

Reeves, S.R. Bastian, P.A., Spivey, J.P., Flumerfelt, R.W., Mohaghegh, S., and Koperna G.J.: “Benchmarking of Restimulation Candidate Selection Techniques in Layered, Tight Gas Sand Formulations Using Reservoir Simulation”, SPE 63096, Proceedings of the SPE Annual Technical Conference and Exhibition, Dallas, October 1-4, 2000.

Abstract
Studies by the Gas Research Institute have revealed that improved methods are needed to cost-effectively identify high-potential restimulation candidate wells. Subsequent research has had the objective of developing such methodologies, and testing them in the field. The techniques being investigated include production statistics, virtual intelligence, and type-curves. For various reasons, field activities have been slow to implement, limiting the feedback needed to fully test each candidate selection method. Therefore a reservoir simulation study was performed to test the methods. The simulation field model consisted of four reservoir layers of variable properties. Wells were drilled in three rounds over a 12-year period (120 total wells). Completion intervals were varied for each well, as were skin factors for individual layers. Before providing the data to the project team for analysis, noise was added. These model features and noise were incorporated into the exercise to best replicate actual field conditions. Restimulation potential was established by "restimulating" each well in the model and observing the incremental production response. Application of the various candidate selection techniques, and comparing the results to the known answer, has yielded several important conclusions. First, simple production data comparisons are not effective at identifying high-potential restimulation candidates; better producing wells tend to be better restimulation candidates. Virtual intelligence techniques were the most successful, correctly identifying over 80% of the theoretical maximum available potential. The type-curve technique was not as effective as virtual intelligence, but still achieved a 75% candidate selection efficiency.

Full paper available at https://www.onepetro.org

Advanced Resources International, Inc., “Assessment of Technology Barriers and Potential Benefits of Restimulation R&D for Natural Gas Wells”, Final Report, GRI- 96/0267, July, 1996.

Kuuskraa, V. A., Prestridge, A. L., and Hansen, J. T.; “Advanced Technologies for Producing Massively Stacked Lenticular Sands”, SPE Gas Technology Symposium, Calgary, Alberta, Canada, SPE No. 35630, pp. 505-514, April 28-May 1, 1996.

Full paper available at https://www.onepetro.org


Coalbed Methane

Gonzalez, R. J., Schepers, K. C., Koperna, G. J., & Oudinot, A. Y. (2009, January 1). Assessment of the Potential and Economic Performance for ECBM Recovery and CO2 Sequestration. Society of Petroleum Engineers. doi:10.2118/SPE 121157-MS

Abstract
An Enhanced Coalbed Methane (ECBM) reservoir simulation study was performed to investigate what levels of initial permeability would be required to successfully implement a CO2 injection project for different levels of coal rank, and whether advanced development strategies could extend the window of applicability to lower permeability coal reservoir environments. To perform the study, a matrix of simulation scenarios that consisted of three coal ranks (low, medium and high), three permeability values (1, 10 and 100 mD), three types of injection wells (vertical damaged, vertical stimulated, and multi-branch horizontal), and two types of production wells (vertical and pinnate) were established.

Results, initially analyzed from a production perspective, lead to unexpected conclusions stimulating the controversy and the initiative for future research. For instance, due to the high CO2/CH4 replacement ratio for low rank coals, and the associated coal swelling and permeability reduction, the study indicated that primary recovery production is essentially identical to those reservoir productions under the proposed injection schemes (and any considered permeability level). Certainly, pinnate producers showed better performances than vertical ones. For medium rank coals, successful sweep can be achieved with vertical wells in a high coal permeability environment, but advanced pattern strategies would be required if the permeability is in the other orders. In high rank coals, coal swelling with CO2 injection is minimized, so successful sweep can be achieved in the high and medium coal permeability environments with vertical wells, but advanced pattern strategies would be required in a 1 mD coal permeability environment.

Corresponding economic analyses accompanying the production implied additional perspectives to be considered for decision management. Promising scenarios from the production point of view are not necessarily profitable under relatively standard conditions. Due to the serious limitations in the existing need knowledge base, these findings can be used as initial screening criteria for identifying reservoir environments and development strategies amenable to CO2-ECBM/sequestration projects.

Full paper available at https://www.onepetro.org

Stevens, S.H., Moodhe, K., and Brunner, D.; “Liuzhuang Coal Mine, Huainan Coal Field, Anhui Province, China: Feasibility Study for Coal Mine Methane Drainage and Utilization”, USEPA, December 14, 2009.

Report available at www.epa.gov/cmop.

Oudinot, A.Y., Schepers, K.C., Gonazlez, R. J. and Reeves, S.R.: “An Intergrated Reservoir Characterization, Geostatistical Analysis, Optimized History-Matching and Performance Forecasting Study of the 9-Section, 30-Well Pump Canyon CO2-ECBM/Sequestration Demonstration Site, San Juan Basin, New Mexico”, presented at the 2008 International Coalbed & Shale Gas Symposium, Paper 0804, Tuscaloosa, Alabama, May 19-23, 2008.

Oudinot, A. Y., Schepers, K. C., and Reeves, S. R.; “Gas Injection and Breakthrough Trends as Observed in ECBM Sequestration Pilot Projects and Field Demonstrations”, presented at the 2007 International Coalbed Methane Symposium, Paper 0714, Tuscaloosa, Alabama, May 21 – 25, 2007

Oudinot, A.Y., Sultana, A., Gonzalez, R.R., Reeves S.R. and Wörmann, M.: “Development of Optimized History-Matched Models for Coalbed Methane Reservoirs”, 2006 International Coalbed Methane Symposium, Paper 0637, Tuscaloosa, Alabama, May 22-26, 2006.

Gonzalez, R.J., Sultana, A., Oudinot, A.Y., and Reeves S.R.: “Incorporating Geostatistical Methods with Monte Carlo Procedures for Modeling Coalbed Methane Reservoirs”, 2006 International Coalbed Methane Symposium, Paper 0638, Tuscaloosa, Alabama, May 22-26, 2006.

Bank, G. C., and Kuuskraa, V. A.; “The Economics of Powder River Basin Coalbed Methane Development”, prepared for U. S. Department of Energy, January, 2006

Oudinot, A.Y., Koperna, G.J., Jr., and Reeves, S.R.: “Development of a Probabilistic Forecasting and History Matching Model for Coalbed Methane Reservoirs”, 2005 International Coalbed Methane Symposium, Paper 0528, Tuscaloosa, Alabama, May 16-20, 2005.

Stevens, S.H., Ferry, J.G., and Schoell, M., 2012. “Methanogenic Conversion of CO2 Into CH4: A Potential Remediation Technology for Geologic CO2 Storage Sites”, prepared for US Department of Energy, Office of Science, Chicago, IL, SBIR Program, DE-FG02-03ER83596, July 13, 2003 to January 13, 2008

Reeves S.R., Gonzalez, R., Gasem, K.A.M., Fitzgerald, J.E., Pan, Z., Sudibandriyo, M., and Robinson, R. L., Jr.: “Measurement and Prediction of Single-and Multi-Component Methane, Carbon Dioxide and Nitrogen Isotherms for U.S. Coals”, 2005 International Coalbed Methane Symposium, Paper 0527, Tuscaloosa, Alabama, May 16-20, 2005.

Reeves S.R. and Oudinot, A.: “The Tiffany Unit N2-ECBM Pilot A Reservoir and Economic Analysis”, 2005 International Coalbed Methane Symposium, Paper 0523, Tuscaloosa, Alabama, May 16-20, 2005.

Stevens, S.H. and Hadiyanto; “Indonesia: Coalbed Methane Indicators and Basin Evaluation”, SPE 88630, SPE Asia Pacific Oil & Gas Conference and Exhibition, Perth, Australia, October 18-20, 2004.

Abstract
Indonesia has thick, low-rank coal deposits that are prospective for coalbed methane (CBM) development but remain untested. Conventional oil and gas wells that drill through these coal seams experience gas kicks and blow outs, good CBM indicators. We analyzed petroleum and coal mining data to perform a comprehensive assessment of Indonesia's CBM resources. We identified 12.7trillion m3 (450 Tcf) of prospective CBM resources within eleven onshore coal basins. Full-cycle development costs in high-graded areas are estimated at$0.70/Mcf. These potential CBM reservoirs could be tested at low cost using coreholes or production "wells of opportunity."

Full paper available at https://www.onepetro.org

von Shoenfeldt, H., Zupanik, J., Wight, D., and Stevens, S.H.; “Unconventional Drilling Methods for Unconventional Reservoirs in the US and Overseas”, International Coalbed Methane Symposium, University of Alabama, Tuscaloosa, Alabama, May 3-7, 2004.

Reeves, S.R., Oudinot, A.Y. and Erickson, D.: “The Tiffany Unit N2 - ECBM Pilot: A Reservoir Modeling Study”, Topical Report, DOE Contract No. DE-FC26-00NT40924, May, 2004.

Reeves, S.R., Davis, D.W. and Oudinot, A.Y.: “A Technical and Economic Sensitivity Study of Enhanced Coalbed Methane Recovery and Carbon Sequestration in Coal”, Topical Report, DOE Contract No. DE-FC26-00NT40924, April, 2004.

Advanced Resources International; “Multi-Seam Well Completion Technology: Implications for Powder River Basin Coalbed Methane Production”, DOE/NETL - 2003/1193, prepared for the U.S. Department of Energy, Office of Fossil Energy and National Energy Technology Laboratory, Strategic Center for Natural Gas, September 2003.

Taillefert, A. and Reeves S. R.: “Screening Model for ECBM Recovery and CO2 Sequestration in Coal”, Coal-Seq V1.0, Topical Report, DOE Contract No. DE-FC26-00NT40924, June, 2003.

Advanced Resources International, Inc., “Assessment of CO2 Sequestration and ECBM Potential of U.S. Coalbeds”, Topical Report, DOE Contract No. DE-FC26-00NT40924, February, 2003.

Advanced Resources International, Inc., “Field Studies of Enhanced Methane Recovery and CO2 Sequestration in Coal Seams”, World Oil, December, 2002.

Advanced Resources International; “Powder River Basin Coalbed Methane Development and Produced Water Management Study”, DOE/NETL-2003/1184, prepared for U.S. Department of Energy, Office of Fossil Energy and National Technology Laboratory Strategic Center for Natural Gas, November 2002.

Stevens, S.H., Brunner, D., and Liu, Z.; “Yangquan Mine CMM-to-Power Project: Technical and Economic Evaluation”, International CMM/CBM Investment Exposition/Symposium, Shanghai, China, November 7-8, 2001.

Stevens, S.H., Sani, K., and Sutarno, H.; “Indonesia’s 337 Tcf of CBM Resource: a Low-Cost Alternative to Gas, LNG”, Oil and Gas Journal, p. 40-45, October 22, 2001.

To access this article, please go to http://www.ogj.com/index.html. Subscription fees may apply.

Stevens, S.H.; “China Coalbed Methane Reaches Turning Point.” Oil and Gas Journal, January 25, 1999, p. 101-106.

To access this article, please go to http://www.ogj.com/index.html. Subscription fees may apply.

Derickson, J.P., Horne, J.S., Fisher, R.D., and Stevens, S.H.; “Huaibei Coalbed Methane Project, Anhui Province, People’s Republic of China”, Society of Petroleum Engineers, SPE 48886, Annual Technical Conference and Exhibition, Beijing, November 2-6, 1998.

Available at https://www.onepetro.org

Stevens, S.H., Spector, D., and Riemer, P.; “Enhanced Coalbed Methane Recovery Using CO2 Injection: Worldwide Resource and CO2 Sequestration Potential”, Society of Petroleum Engineers, SPE 48881, Annual Technical Conference and Exhibition, Beijing, November 2-6, 1998.

Available at https://www.onepetro.org

Stevens, S.H., Spector, D., and Kuuskraa, V.K., “Enhanced Recovery of Coalbed Methane.” Report for International Energy Agency Greenhouse Gas R&D Programme, IEA/CON/97/27, June 1998.

Stevens, S. H. and Spector, D.; “Enhanced Coalbed Methane Recovery: Worldwide Applications and CO2 Sequestration Potential”, Final Report IEA/CONS/97/27, prepared for the IEA Greenhouse Gas R & D Programme, 1998.

Stevens, S.H., Kuuskraa, J., and Schraufnagel, R.; “Technology Spurs Growth of U.S. Coalbed Methane”, Oil & Gas Journal, p. 56-63, January 1, 1996.

To access this article, please go to http://www.ogj.com/index.html. Subscription fees may apply.

Kuuskraa, V.A., Reeves, S.R., Schraufnagel, R.A., Spafford, S.P.: “Economic and Technical Rationale for Remediating Inefficiently Producing Eastern Antrim Shale and Coalbed Methane Wells”, SPE 26894, Proceedings of the SPE Eastern Regional Meeting, Pittsburgh, November 2-4, 1993.

Available at https://www.onepetro.org

Cox, D. O., Decker, A. D., Stevens, S. H.: “Analysis of Fruitland Water Production Treatment and Disposal, San Juan Basin”, Topical Report GRI-93/0288, prepared for Gas Research Institute, Contract No. 5091-214-2316, June, 1993.

Stevens, S.H., Sheehy, L., Zhu, H., and Yuan, B.; “Reservoir Analysis of the Tangshan Coalbed Methane Prospect, Hebei Province, The People's Republic of China”, Society of Petroleum Engineers, SPE Paper 24904, presented at the 67th Annual Technical Conference, Washington, D.C., October 4-7, 1992.

Available at https://www.onepetro.org

Stevens, S. H., Lombardi, T. E., Kelso, B. S., and Coates, J. M.; “A Geologic Assessment of Natural Gas from Coal Seams in the Raton and Vermejo Formations, Raton Basin”, GRI Topical Report 92/0345, June, 1992.

Advanced Resources International, Inc., “A Geologic Assessment of Natural Gas from Coal Seams in the Menefee Formation, San Juan Basin”, GRI Topical Report 88/0303, July, 1990.

Kelafant, J. R. and Boyer, C.M.; “A Geologic Assessment of Natural Gas from Coal Seams in the Central Appalachian Basin”, GRI Topical Report 88/0302, December, 1988.

Kelso, B. S., Wicks, D. E., and Kuuskraa, V. A.; “A Geologic Assessment of Natural Gas from Coal Seams in the Fruitland Formation, San Juan Basin”, GRI Topical Report 87/0341, March, 1988.

Kelafant, J. R., Wicks, D. E., and Kuuskraa, V. A.; “A Geologic Assessment of Natural Gas from Coal Seams in the Northern Appalachian Coal Basin”, GRI Topical Report 88/0039, March, 1988.

McFall, K.S., Wicks, D. E., and Kuuskraa, V. A.; “A Geologic Assessment of Natural Gas from Coal Seams in the Warrior Basin, Alabama”, GRI Topical Report 86/0272, November 1986.

McFall, K.S., Wicks, D. E., Kuuskraa, V. A. and Sedwick, K. B.; “A Geologic Assessment of Natural Gas from Coal Seams in the Piceance Basin, Colorado”, GRI Topical Report 87/0060, November 1986.


Unconventional Resources

Stevens, S. H., & Moodhe, K. D. (2015, November 18). Evaluation of Mexico’s Shale Oil and Gas Potential. Society of Petroleum Engineers. doi:10.2118/SPE 177139-MS.

Abstract
Mexico has significant oil and gas resource potential in Jurassic and Cretaceous age shale formations. These shale deposits -- which correlate with productive shale plays in the USA -- appear prospective but are still in the early stage of exploration and thus remain poorly characterized. Early shale exploration wells tested mostly low rates, but a recent oil well made 500 bopd while a shale gas well reached 10.9 MMcfd.

The Mexican government plans to offer shale exploration blocks through an international auction. As part of a multi-client study, the authors have greatly expanded the geologic and reservoir data set we developed during an earlier scoping-level study conducted for the US Energy Information Administration (EIA). The additional geologic data support our initial view that Mexico has some of the largest and best quality shale potential outside the US and Canada. Risked, technically recoverable resources were estimated in the EIA/ARI study at 13.1 BBO of oil and 545 Tcf of natural gas.

Detailed geologic mapping and analysis indicates the two most prospective liquids-rich shale areas in Mexico occur within onshore portions of the Burgos and Tampico-Misantla basins, which have transport infrastructure and well services. Significant potential also exists in the Veracruz, Macuspana, Sabinas, and other onshore basins, but those areas tend to be structurally more complex and/or are mostly in the dry gas window.

The U. Cretaceous Eagle Ford Shale (in the Burgos) and correlative Agua Nueva Formation (in the Tampico-Misantla) have high TOC and brittle carbonate-rich mineralogy, but their net prospective area is reduced due to often shallow burial depth and low thermal maturity. A better target appears to be the U. Jurassic Pimienta and La Casita formations, which can be thick (~200 m), at prospective depth over much larger areas, are in the volatile oil to wet gas windows, and frequently overpressured, although TOC is lower than in the Agua Nueva.

Full paper available at https://www.onepetro.org

Advanced Resources International (ARI): “World Shale Gas and Shale Oil Resource Assessment”, prepared for the U.S. Energy Information Administration (EIA), the statistical and analytical agency within the U.S. Department of Energy, June, 2013 . Full Report , Executive Summary and Results , Individual chapters: Executive Summary and Study Results, Study Methodology, I. Canada, II. Mexico, III. Australia, IV. N. South America, V. Argentina, VI. Brazil, VII. Other S. South America, VIII. Poland (Including Lithuania and Kaliningrad), IX. Russia, X. Eastern Europe (Bulgaria, Romania, Ukraine), XI. United Kingdom, XII. Spain, XIII. Northern and Western Europe, XIV. Morocco (Including Western Sahara and Mauritania), XV. Algeria, XVI. Tunisia, XVII. Libya, XVIII. Egypt, XIX. South Africa, XX. China, XXI. Mongolia, XXII. Thailand, XXIII. Indonesia, XXIV. India/Pakistan, XXV. Jordan, and XXVI. Turkey.

Advanced Resources International (ARI): “World Shale Gas Resources: An Initial Assessment of 14 Regions Outside the United States”, prepared for the U.S. Energy Information Administration (EIA), the statistical and analytical agency within the U.S. Department of Energy, April, 2011.

Kuuskraa, V.A.: “Worldwide Gas Shales and Unconventional Gas: A Status Report”, prepared and presented at the recent United Nations Climate Change Conference, COP15, "Natural Gas, Renewables and Efficiency: Pathways to a Low-Carbon Economy" sponsored by the American Clean Skies Foundation (ACSF), the UN Foundation (UNF) and the Worldwatch Institute, Copenhagen. December 7 - 18, 2009

Kuuskraa, V.A.: “Paradigm Shift in Domestic Natural Gas Resources, Supplies and Costs”, presented to the EFI Gas-to-Market & Energy Conversion Forum Washington, D.C. September 21, 2009

Kuuskraa, V.A.: “Challenges Facing Increased Production and Use of Domestic Natural Gas”, presented to the Global Energy and Environment Initiative (GEEI), Paul H. Nitze School of Advanced International Studies, Johns Hopkins University, Washington, D.C. September 16, 2009

Kuuskraa, V.A.: “Paradigm Shift in the Domestic Natural Gas Resource Base”, a new Advanced Resources' presentation by Mr. Vello A. Kuuskraa presented at the Clean Technology Conference & Expo, at the George R. Brown Convention Center in Houston, TX. May 3 - 7, 2009

Kuuskraa, V.A.: “Reserves, Production Grew Greatly During Last Decade”, Oil & Gas Journal, Vol 105.33, September 3, 2007, pp 35-39.

To access this article, please go to http://www.ogj.com/index.html. Subscription fees may apply.

Kuuskraa, V. A.; “A Decade of Progress in Unconventional Gas”, Advanced Resources International, Inc. White Paper, Unconventional Gas Series, July, 2007.

Kuuskraa, V. A.: “The Unconventional Gas Resource Base”, Advanced Resources International, Inc. White Paper, Unconventional Gas Series, July, 2007.

Riestenberg, D., Ferguson, R., and Kuuskraa, V. A.; “New and Emerging Unconventional Gas Plays and Prospects”, Advanced Resources International, Inc. White Paper, Unconventional Gas Series, July, 2007.

Reeves, S. R., Koperna, G. J., and Kuuskraa, V. A.; “Nature and Importance of Technology Progress for Unconventional Gas”, Advanced Resources International, Inc. White Paper, Unconventional Gas Series, July, 2007.

Godec, M. L., Van Leeuwen, T., and Kuuskraa, V. A.; “Economics of Unconventional Gas”, Advanced Resources International, Inc. White Paper, Unconventional Gas Series, July, 2007.

Kuuskraa,V. A., Godec, M. L., and Reeves, S. R.; “Outlook for Unconventional Gas: The Next Decade”, Advanced Resources International, Inc. White Paper, Unconventional Gas Series, July 24, 2007.

Kuuskraa, V. A. and Bank, G.; “Gas from Tight Sands, Shales, a Growing Share of U.S. Supply”, Oil & Gas Journal, Vol. 101.47, December 8, 2003, pp 34-43.

To access this article, please go to http://www.ogj.com/index.html. Subscription fees may apply.

Eppink, J. F., Kuuskraa, V. A., & Kuck, B. T. (2001, January 1). Assessment of Natural Gas and Oil Supply Issues in the Deepwater Gulf of Mexico. Offshore Technology Conference. doi:10.4043/SPE 13225-MS

Abstract
Royalty relief is one of the premier topical issues concerning producers in the deepwater Gulf of Mexico (GOM). This paper provides results of a scenario analysis assessing the presence and absence of the Royalty Relief Act provisions on GOM reserves, production and governmental revenues. Results indicate substantive benefits to the Nation for continuance of royalty relief.

Full paper available at https://www.onepetro.org

Mohaghegh, S., Popa, A., Koperna, G., Hill, D., “Reducing the Cost of Field-Scale Log Analysis Using Virtual Intelligence Techniques”, SPE No. 57454; presented at the 1999 SPE Eastern Regional Meeting, October 21-22, 1999, Charleston, WV.

Available at https://www.onepetro.org

Stevens, S.H., Kuuskraa, J. and Kuuskraa, V.A.: “Unconventional Natural Gas in the United States: Production, Reserves, and Resource Potential (1991-1997)”, report prepared for the California Energy Commission, Contract No. 300-97-011, December, 1998.

Collett, T. S., Kuuskraa, V. A.; “Hydrates Contain Vast Store of World Gas Resources”, Oil and Gas Journal, Vol. 96, No. 19, May 11, 1998, pp. 90-95.

Kuuskraa, V. A.; “Diverse Gas Plays Lurk in Gas Resource Pyramid”, Oil and Gas Journal, Vol. 96, No. 23, June 8, 1998, pp. 123-130.

Kuuskraa, V. A.; “Deep Gas Poses Opportunities, Challenges to U.S. Operators”, Oil and Gas Journal, Vol. 96, No. 18, May 4, 1998, pp. 133-146.

Kuuskraa, V. A.; “Outlook Bright for U.S. Natural Gas Resources”, Oil and Gas Journal, Vol. 96, No. 15, April 13, 1998, pp. 92-97.

Kuuskraa, V. A., and Stevens S. H.; “How Unconventional Gas Prospers Without Tax Incentives”, Oil and Gas Journal, Vol. 93 No. 50 December, 11, 1995, pp. 76-81.

Kuuskraa, V. A; “Steps to Assess Resource Economics Covered”, Oil and Gas Journal, Vol. 87, No. 52, December 25, 1989, pp 121-122, 124-125. (Co-Author)


Enhanced Oil Recovery

Residual Oil Zone “Fairways” and Discovered Oil Resources: Expanding the Options for Carbon Negative Storage of CO2. V. Kuuskraa, R. Petrusak and M. Wallace, Advanced Resources International prepared and presented at the 13th International Conference on Greenhouse Gas Control Technologies, GHGT-13, 14-18 November 2016, Lausanne, Switzerland

Abstract

Recently completed geophysical and reservoir engineering-based investigations have identified the presence of large Residual Oil Zone (ROZ) “fairways” in the Permian and numerous other U.S. and international oil basins. These ROZ “fairways” offer a third geologically viable option, in addition to saline formations and mature oil fields, for storing CO2 captured from industrial sources.

The benefits of pursuing ROZ “fairways” as a third geologic option for storing CO2 are many. First, the ROZ “fairways” offer a carbon negative option for storing CO2, where the carbon content of the injected CO2 significantly exceeds the carbon content of the by-product oil recovered as part of injecting CO2. Second, the “fairways” are extensive and continuous, with an established upper seal and have a massive volume of reservoir space for secure, long-term CO2 storage. Third, for much of the ROZ resource, the production of by-product oil will cover the costs of installing and operating the CO2 storage system while also providing revenues for covering a portion of the costs of capturing CO2. Finally, the ROZ “fairways” are located outside and beyond the structural closure of existing oil fields, providing new, accessible geologic settings for storing CO2.

In summary, the identification and characterization of ROZ fairways adds a significant new option for efficiently and economically storing CO2. Our discussions with scientists from numerous other countries, namely Australia, Colombia, Kuwait, Lithuania, Norway and Saudi Arabia, confirm that ROZ “fairways” are not unique to U.S. oil basins, but are likely a major international phenomena that can support expanded application of CO2 capture, utilization and storage.

Link will be posted when papers are published. For more information on the meeting, visit http://www.ghgt.info/

Potential Issues and Costs Associated with Verifying CO2 Storage During and After CO2-EOR. M.L. Godec, D. Riestenberg and S. Cyphers, Advanced Resources International. Paper prepared and presented at the 13th International Conference on Greenhouse Gas Control Technologies, GHGT-13, 14-18 November 2016, Lausanne, Switzerland

Abstract

Numerous legal and regulatory frameworks in the U.S. and globally are acknowledging the opportunity for greenhouse gas (GHG) reductions provided by combining the long-term storage of CO2 in association with carbon dioxide enhanced oil recovery (CO2-EOR), or in implementing a CO2 storage project after completion of CO2-EOR operations. These include the U.S. Environmental Protection Agency (EPA), the International Organization for Standardization (ISO), the State of California, and the Intergovernmental Panel on Climate Change (IPCC), among many.

One objective of this paper is to characterize the potential issues and estimated costs associated with adapting a CO2-EOR project to enable it to get “credit” for stored CO2, as well as for converting a CO2-EOR project to a “pure” CO2 storage project. Several scenarios are considered in terms of the acceptable activities that a CO2-EOR operator would need to pursue to get “credit” for stored CO2, as well as for what would be required for converting a CO2-EOR project to a CO2 storage project. These potential scenarios are applied to several fields currently undergoing CO2-EOR operations to approximate a “real world” assessment of the potential implementation of this strategy.

Two facilities were assumed for this assessment, based on representative CO2-EOR projects in the Permian Basin of West Texas and Gulf Coast of the U.S. For each, two regulatory scenarios were considered for verifying and documenting CO2 storage – a Reference Case and a Stringent Case.

For the cases assuming CO2 storage with CO2-EOR, only the incremental costs associated with verifying and documenting CO2 storage are considered. Twenty years of injection are assumed, with 73 million metric tons of injected and stored CO2 assumed for the Permian Basin case, and 27 million metric tons assumed for the Gulf Coast case. A ten-year post-injection site care (PISC) period is assumed. Total project expenditures for verifying/documenting CO2 storage, on the basis of total expenditures (undiscounted) per metric ton of stored CO2, equate to $1.64/metric ton in the Reference Case, and $4.18/metric ton for the Stringent Case.

For the cases assuming CO2 storage after CO2-EOR, it is important to keep in mind that MRV costs represent only a portion of overall storage costs. In most cases, a large portion (in fact, the majority) of the costs associated with CO2 storage project in a converted CO2-EOR project are those associated with operating the wells, equipment, and surface facilities. For this scenario, in the Reference Case, a 10-year PISC phase is assumed, while in the Stringent Case, a 50-year PISC period is assumed.

For the Permian Basin case, total project expenditures for CO2 storage after CO2-EOR $9.02/metric ton in the Reference Case, and $21.13/metric ton for the Stringent Case. For the Gulf Coast setting, total project expenditures for CO2 storage after CO2-EOR are $5.21/metric ton in the Reference Case and $12.09/metric ton for the Stringent Case.

Finally, potential conflicts between USEPA requirements and state-level mineral property, resource conservation, and environmental law in the United States remain a concern, and will need to be addressed.

Link will be posted when papers are published. For more information on the meeting, visit http://www.ghgt.info/

U.S. DOE/RPSEA, “Identifying and Developing Technology for Enabling Small Producers to Pursue the Residual Oil Zone (ROZ) Fairways of the Permian Basin, San Andres”, 10121.17.FINAL, December 2015, Chapter 7 (Task 9.0) – Estimate of the Permian Basin San Andres ROZ Resources written by Advanced Resources International, Inc.

Full report available at http://www.rpsea.org/projects/10123-17/

Kuuskraa, V. A., & Malone, T. (2016, May 2). CO2 Enhanced Oil Recovery for Offshore Oil Reservoirs. Offshore Technology Conference. doi:10.4043/27218-MS

Abstract

This paper presents the results of a recent analysis of applying carbon dioxide enhanced oil recovery (CO2-EOR) to oil reservoirs in the offshore Gulf of Mexico (GOM). The study started with a data base from the Bureau of Ocean Energy Management (BOEM) that contained 531 oil fields with a total original oil in-place (OOIP) of 69 billion barrels. The study excluded 391 of these oil fields, representing 35% of the OOIP, as not being amenable to CO2-EOR based on their size, minimum miscibility pressure, and residual oil saturation. The study then evaluated the remaining 140 GOM offshore oil fields, containing 696 individual reservoirs, for their technical and economic viability for CO2-EOR.

Crude oil production and CO2 injection profiles were calculated for each reservoir using a stream-tube finite-difference simulator. The calculation of economic viability was based on a crude oil price of $90/bbl, a CO2 price of $1.59/Mscf ($30 $/MtCO2) at the capture facility plant gate, an 18.75% royalty, and a minimum 20% rate of return, before taxes. With Current CO2-EOR Technology, the economically recoverable resource (ERR) from the GOM offshore is 0.8 billion barrels, a small fraction of the technically recoverable resource (TRR) of 23.5 billion barrels. With Next Generation CO2-EOR Technology, the ERR increases significantly to 14.9 billion barrels.

Full paper available at https://www.onepetro.org

Carpenter, S. M., & Koperna, G. (2015, August 4). Development of the First Internationally Accepted Standard for Geologic Storage of Carbon Dioxide Utilizing Enhanced Oil Recovery (EOR) Under the International Standards Organization (ISO) Technical Committee TC-265. Society of Petroleum Engineers. doi:10.2118/178506-MS

Abstract

The Carbon Capture Utilization & Sequestration (Storage) (CCUS) marketplace is lacking standardization and therefore the ability to allow CCUS projects to be advance as Clean Development Mechanism (CDM) projects as well as to advance to full scale commercialization. An international effort between the United States and Canada, funded by the International Performance Assessment Centre for Geologic Storage of Carbon Dioxide (IPAC-CO2 Research Inc.), and managed by CSA Standards, have developed the first internationally recognized Standard for the geologic storage of carbon dioxide (Z-741). The Z-741 Standard has been adopted by the Standards Council of Canada (SCC) and is available to the American National Standards Institute (ANSI). As a direct result of Z-741, the International Standards Organization (ISO) has created a technical committee to advance the development of comprehensive standards that address CCUS.

International Organization for Standardization (ISO) Technical Committee (TC) 265, Carbon dioxide capture, transportation, and geological storage, recently announced the creation of a new working group (WG) focused on standardization in connection with enhanced oil recovery (EOR) related carbon dioxide (CO2) storage. The new group, WG 6, CO2-EOR, was created at the TC-265 third plenary meeting, held at the China University of Petroleum–Beijing on September 23–25, 2013.

During the meeting, the U.S. and Norway proposed the creation of WG 6 following a presentation on CO2-EOR. The U.S. Technical Advisory Group (TAG) to ISO TC 265, administered by CSA Group, an American National Standards Institute (ANSI) organizational member and accredited standards developer, named the U.S. as convener and Norway as co-convener.

The new working group will focus on standardization efforts associated with low-pressure subsurface oil field operating environments and related CO2 recovery operations, as well as the harmonization of CO2 supplies with EOR operations both on a daily basis and over multi-year operational horizons, among other topics. WG 6 has issued an international call for expert participation in its development of standards and other documents related to CO2 EOR.

This paper will address key issues experienced in the standard development process, which is a technical, consensus-based facilitated process. Membership of the Committee is drawn from experts with full project life cycle knowledge and experience – general interest, operators/industry, regulatory, and consultant/service providers, which represent a balance of stakeholder needs.

Full paper available at https://www.onepetro.org

Kuuskraa, V.A., Malone, T. and P. DiPietro, “CO2-EOR Offshore Resource Assessment”, prepared for the U.S. Department of Energy/NETL, DOE NETL Contract Number DE-FE0004001, report DOE/NETL-2014/1631, June 5, 2014. http://www.netl.doe.gov/energy-analyses/temp/FY14_CO2-EOROffshoreResourceAssessment_060114.pdf

Kuuskraa, V.A., and M. Wallace, “CO2-EOR Set for Growth as New CO2 Supplies Emerge”, Oil & Gas Journal, EOR/Heavy Oil Survey issue, April 7, 2014/Volume 112.4, pp. 67-76.

To access this article, please go to http://www.ogj.com/index.html. Subscription fees may apply.

Dipietro, P., Kuuskraa, V., & Malone, T. (2014, April 12). Taking CO2-Enhanced Oil Recovery to the Offshore Gulf of Mexico. Society of Petroleum Engineers. SPE 169103-MS.

Abstract

This paper evaluates the recoverable crude oil resource associated with applying carbon dioxide enhanced oil recovery (CO2 EOR) to reservoirs in the offshore Gulf of Mexico (GOM). Using data maintained by the Bureau of Ocean Energy Management (BOEM), a database containing 531 oil fields with a total original oil in-place (OOIP) of 69 billion barrels was used for the study. A total of 391 fields, representing 35% of the OOIP, were screened out at as not amenable to CO2 EOR based on size, residual oil saturation, and/or well-spacing. For the remaining 140 oil fields (containing 696 reservoirs), the data elements required to model a CO2 EOR flood, such as sweep efficiency and heterogeneity, were derived using a variety of methods. Crude oil production and CO2 demand profiles were produced from stream-tube finite-difference simulations for each oil-bearing reservoir. The study assumes that groups of proximate fields will be served by an anchor CO2 supply pipeline (one billion scf per year CO2) at a levelized transportation cost of $1.06/MscfCO2 (equivalently 20$/mtCO2). The economic determinations are based on a crude oil price of $90/bbl, CO2 price of $1.59/Mscf (30 $/MtCO2) at the capture facility plant gate, 18.75% royalty, and a 20% rate of return before taxes. BOEM projects that 182 billion barrels of OOIP remain undiscovered, two and a half times the discovered resource. Data from the analysis of discovered oil fields was used to estimate the expected CO2 EOR oil recovery from the undiscovered oil fields. Under the current CO2 EOR Technology scenario, the economically recoverable resources (ERR) is 0.8 billion barrels, a small fraction of the technically recoverable resource (TRR) of 23.5 billion barrels. The average efficiency of CO2 use in the ERR oil fields is estimated to be 7.2 Mscf/bbl and the associated demand for CO2 supply is 5.8 TCF. Under a scenario with Next Generation CO2 EOR performance, the ERR increases significantly to 14.9 billion barrels and 74 TCF of CO2 demand, consistent with an improved use efficiency of 5.0 MscfCO2/bbl.

Full paper available at https://www.onepetro.org

Godec, M. L., 2014. Acquisition and Development of Selected Cost Data for Saline Storage and Enhanced Oil Recovery (EOR) Operations, DOE/NETL-2014/1658, prepared by Advanced Resources International under DOE NETL Contract Number DE-FE0004001.

https://www.netl.doe.gov/File%20Library/Research/Energy%20Analysis/Publications/saline-and-eor-operation-cost-estimation-recommendations-ari-final-7-2.pdf

Cornerstone Magazine “CO2 Enhanced Oil Recovery: The Enabling Technology for CO2 Capture and Storage”, written by Vello Kuuskraa, President, Advanced Resources International and Phil DiPietro, Strategic Energy and Planning Division, U.S. DOE/NETL, Winter 2013, Volume 1, Issue 4.

To access this article, please go to: http://www.nxtbook.com/nxtbooks/wiley/cornerstone_2013winter/#/38

Koperna, G. J., Riestenberg, D. E., Kuuskraa, V. A., Rhudy, R., Trautz, R. C., Hill, G., & Esposito, R. A. (2012, January 1). The SECARB Anthropogenic Test: The First US Integrated Capture, Transportation, and Storage Test. Carbon Management Technology Conference. doi:10.7122/SPE 151230-MS

Abstract

The United States Department of Energy (DOE) seeks to validate the feasibility of injecting, storing and monitoring CO2 in the subsurface (geologic storage) as an approach to mitigate atmospheric emissions of CO2. In an effort to promote the development of a framework and the infrastructure necessary for the validation and deployment of carbon sequestration technologies, DOE established seven Regional Carbon Sequestration Partnerships (RCSPs).

The Southeast Regional Carbon Sequestration Partnership (SECARB), whose lead organization is the Southern States Energy Board (SSEB), represents 13 States within the south eastern United States of America (USA). The SECARB Anthropogenic Test R&D project is a demonstration of the deployment of CO2 capture, transport, geologic storage and monitoring technology. This project is an integral component of a plan by Southern Company, and its subsidiary, Alabama Power, to demonstrate integrated CO2 capture, transport and storage technology. The capture component of the test takes place at the James M. Barry Electric Generating Plant (Plant Barry) in Bucks, Alabama. The capture facility, equivalent to 25 MW, will utilize post-combustion amine capture technology licensed by Mitsubishi Heavy Industries America. CO2 captured at the plant will be transported by pipeline for underground storage in a deep, saline geologic formation within the Citronelle Dome located in Citronelle, Alabama.

Starting in the first quarter of 2012, up to 550 tonnes of CO2 per day will be captured and transported twelve miles by pipeline to the storage site for injection and subsurface storage. The injection target is the lower Cretaceous Paluxy Formation which occurs at 9,400 feet. Transportation and injection operations will continue for one to two years. Subsurface monitoring will be deployed through 2017 to track plume movement and monitor for leakage. This project will be one of the first and the largest fully-integrated commercial prototype coal-fired carbon capture and storage projects in the USA. This paper will discuss the results to date, including permitting efforts, baseline geologic analysis and detailed reservoir modeling of the storage site, framing the discussion in terms of the overall goals of the project.

Full paper available at https://www.onepetro.org

Dipietrio, P., Balash, P., & Wallace, M. (April 2012). A Note on Sources of CO2 Supply for Enhanced-Oil-Recovery Operations, SPE Economics and Management. http://www.netl.doe.gov/energy-analyses/temp/FY12_ANoteonSourcesofCO2SupplyforEnhancedOilRecoveryOperations_040112.pdf

Godec, M.L., 2011. “Global Technology Roadmap for CCS in Industry Sectoral Assessment CO2 Enhanced Oil Recovery”, prepared for United Nations Industrial Development Organization (UNIDO). https://www.unido.org/fileadmin/user_media/Services/Energy_and_Climate_Change/Energy_Efficiency/CCS/EOR.pdf

“Improving Domestic Energy Security and Lowering CO2 Emissions with “Next Generation” CO2-Enhanced Oil Recovery (CO2-EOR)”, DOE/NETL-2011/1504, July 2011, prepared by Advanced Resources International, Inc., V. Kuuskraa, T. Van Leeuwen and M. Wallace.

http://www.netl.doe.gov/File%20Library/Research/Energy%20Analysis/Publications/DOE-NETL-2011-1504-NextGen_CO2_EOR_06142011.pdf

Advanced Resources International, Inc.; “U.S. Oil Production Potential from Accelerated Deployment of Carbon Capture and Storage”, White Paper, Arlington, VA, March, 2010. Press Release

Kuuskraa, V. A., Koperna, G. J., & Schepers, K. C. (2010, January 1). CO2-Storage Engineering: Real Solutions to Real Problems. Society of Petroleum Engineers. doi:10.2118/SPE 139512-MS

Abstract

Deep saline aquifers offer the potential for storing large volumes of CO2. However, with conventional CO2 storage well design and operating practices, only a small fraction of this large CO2 storage potential can be productively used. Numerous alternative designs and practices, which utilize the reservoir's internal architecture and draw on CO2 storage engineering expertise, could enable CO2 storage operators to more efficiently and fully utilize a saline formation's storage capacity. This would help reduce the areal extent of the CO2 plume and its risk footprint. It would also help reduce the number of CO2 injection wells and patterns that would need to be developed.

This paper, entitled "CO2 Storage Engineering: Real Solution to Real Problems??, discusses practical CO2 storage options that have been proposed for significantly increasing CO2 storage performance at three challenging saline reservoir settings.

Full paper available at https://www.onepetro.org

Koperna, G. J., Riestenberg, D. E., Petrusak, R. L., Esposito, R. A., & Rhudy, R. (2009, January 1). Lessons Learned While Conducting Drilling and CO2 Injection Operations at the Victor J. Daniel Power Plant. Society of Petroleum Engineers. doi:10.2118/SPE 124003-MS

Abstract

This paper will discuss the lessons learned from a CO2 pilot injection in southeastern Mississippi, highlighting those issues that are unique to a first-of-its-kind pilot injection at a power plant as well as unexpected results from applying conventional oil and gas technology to tracking CO2 in the subsurface.

Southern Company's Mississippi Power Victor J Daniel, Jr. electric generating facility is hosting a USDOE sponsored CO2 sequestration demonstration as part of the Southeast Carbon Sequestration Regional Partnership. The primary goal of this demonstration is to provide the foundation for safe and secure storage of CO2 in a deep saline reservoir within the confines of a power plant's property boundary.

Major field operations included: (a) collection of baseline data for subsequent monitoring, verification and accounting (MVA); (b) preparing the drill site; (c) drilling and completing the CO2 injection and observation wells, (d) characterizing the reservoir using core analyses, (e) baseline geophysical well logging and seismic surveying operations, (f) injecting more than 3,000 tons of CO2, (g) post-injection time-lapse geophysical well logging and seismic surveying operations, and (h) site closure. During the execution of these operations, additional activities unique to operations on the plant property included: (a) site access agreements and restrictions, (b) site preparation, (c) site reclamation, (d) advanced notification of field activities, and (e) operational monitoring.

With regard to the application of conventional oil and gas protocols to a sequestration pilot, there were several unexpected results, including those obtained by geophysical logging, seismic surveys, and wellhead and bottomhole pressure data acquisition.

Full paper available at https://www.onepetro.org

Kuuskraa, V. A. (2009, January 1). Cost-Effective Remediation Strategies for Storing CO2 in Geologic Formations. Society of Petroleum Engineers. doi:10.2118/SPE 126618-MS

Abstract

Because storage of CO2 for climate change mitigation is still an emerging industry, very little has been written on the topic of cost-effective remediation strategies for geological storage of CO2. The purpose of this presentation and paper is to begin to fill this gap in publically available technical information.

Much of the background that serves as the technical and experiential source for remediation of CO2 storage wells and sites has been drawn from our experience with the gas storage and the CO2 enhanced oil recovery industries. This paper compiles these past experiences and adds an overlay of the unique facets of geological storage for establishing a remediation strategy and a workable plan for CO2 storage, particularly in saline formations.

In addition, the paper highlights the importance of thorough site selection, rigorous well design and completion practices and the need for a monitoring system that provides an "early warning” of impending problems. The paper also reviews advanced well remediation strategies used by the gas storage industry to restore well productivity of potential value to establishing cost-effective CO2 storage in lower permeability formations.

Full paper available at https://www.onepetro.org

Kuuskraa, V. A. (2008, January 1). Maximizing Oil Recovery Efficiency and Sequestration of CO2 with “Next Generation” CO2-EOR. Society of Petroleum Engineers.

Abstract

This presentation was an SPE Distinguished Lecture during 2007-2008.

Injection of CO2 into depleted and near-depleted oil reservoirs offers the potential for two mutually beneficial results - - increasing oil recovery while sequestering industrial emissions of carbon dioxide (CO2). This presentation examines how alternative technology designs and operating strategies may enable industry to significantly improve CO2-EOR oil recovery efficiencies from the traditional 8% to 12% of original oil in-place (OOIP) to potentially over 20%OOIP, while also significantly increasing the sequestration of CO2.

The presentation draws on laboratory work, reservoir simulation and in depth assessments of significant CO2-EOR field tests that show promise for high oil recovery. The insights gained from these sources are combined to show how injecting larger volumes of CO2, integrating horizontal wells with close vertical well spacing, rigorously managing the CO2-EOR operation, and controlling the conformance of the CO2 flood could lead to increased oil recovery efficiencies from CO2-EOR.

The presentation then examines how the sequestration of CO2 could be optimized both during and after completion of the oil recovery phase in mature oil reservoirs.

Full paper available at https://www.onepetro.org

Riestenberg, D., Koperna, G., Kuuskraa, V. A., and Esposito, R.: “Using Reservoir Architecture to Maximize CO2 Storage Capacity”, Advanced Resources International, Inc. and Southern Company Services, Inc. October, 2008. 118939-MS SPE Conference Paper – 2008

Abstract

This work explores, using reservoir simulation, the impact of reservoir architecture on CO2 plume movement and the reservoir's storage capacity. Subsurface flow of CO2 in the presence of shale "baffles??, or lack thereof, will be reviewed in conjunction with other reservoir characteristics that influence flow such as formation dip, capillary pressure, pore volume trapping, and the rate of CO2 dissolution. Recent geologic and reservoir data collected from the Tuscaloosa Formation at the Mississippi Test Site (a Southeastern Regional Carbon Sequestration Partnership CO2 sequestration pilot test) will be used as the case study for evaluating alternative CO2 storage engineering concepts for maximizing CO2 storage capacity. The Tuscaloosa Formation is a thick, porous, permeable, regionally extensive saline reservoir occurring throughout the Gulf Coast and is considered a promising target for large-scale CO2 storage.

Full paper available at https://www.onepetro.org

Bank, G.C., Riestenberg, D. and Koperna, G.J.: “CO2-Enhanced Oil Recovery Potential of the Appalachian Basin”, SPE 111282-MS presented at the 2007 Eastern Regional Meeting, Lexington, 17-19 October, 2007.

Abstract

The Appalachian Basin states of New York, Pennsylvania, Ohio, West Virginia and Kentucky have a long, rich history of oil production, with current estimates of cumulative oil production at approximately 3.5 billion barrels of oil. However, estimates of the original oil in-place (OOIP) in the region's mature oil fields suggest that nearly 14 billion barrels were in-place prior to the beginning of production more than a century ago. Although early production data are often "best guesses”, the remaining oil in place in this Basin appears to be on the order of 10 billion barrels. Without new efforts, this oil may remain permanently "stranded” following secondary recovery efforts and field closure.

One manner by which a portion of this stranded resource can be recovered is through the use of carbon dioxide enhanced oil recovery (CO2-EOR). The merits of CO2 miscible flooding are well documented and have been demonstrated for more than 30 years in Texas' Permian Basin, with CO2-EOR efforts currently increasing in the Gulf Coast and the Rocky Mountain Basins. With the current strong oil price situation, the oil producers in the Appalachian Basin may be interested in the CO2-EOR potential in the Basin.

This paper follows a series of reports entitled "Basin-Oriented CO2-EOR Assessment” of the United States1 with an assessment of the Appalachian Basin oil producing states of New York, Pennsylvania, Ohio, West Virginia, and Kentucky. Reservoir simulation using detailed, representative data from major oilfields throughout the region indicate that 1,230 million barrels may become technically recoverable if advanced CO2-EOR technology is utilized. The economically recoverable resource will depend on future oil prices and CO2 costs.

Full paper available at https://www.onepetro.org

Kuuskraa, V., “Undeveloped US Oil-Resources: A Big Target for Enhanced Oil Recovery”, World Oil, pp. 65-69, August, 2006.

To access this article, please go to http://www.worldoil.com/. Subscription fees may apply.

Sultana, A., Oudinot, A., Gonzalez, R., and Reeves, S.R.: “BOAST98-MC: A Probabilistic Simulation Module for BOAST 98”, Final Report and Users Manual, DOE Contract No. DE-FC26-04NT15528, June, 2006.

Kuuskraa, V. A. and Koperna, G. J.; “Evaluating the Potential for 'Game Changer' Improvements in Oil Recovery Efficiency from CO2 Enhanced Oil Recovery”, prepared for U.S. Department of Energy, Office of Fossil Energy - Office of Oil and Natural Gas, February, 2006.

Koperna, G. J., Kuuskraa, V. A.; “Technical Oil Recovery Potential from Residual Oil Zones: Big Horn Basin”, prepared for U.S. Department of Energy, Office of Fossil Energy - Office of Oil and Natural Gas, February, 2006.

Koperna, G. J., Kuuskraa, V. A.; “Assessing Technical and Economic Recovery of Oil Resources in Residual Oil Zones”, prepared for U.S. Department of Energy, Office of Fossil Energy - Office of Oil and Natural Gas, February, 2006.

Koperna, G. J., Kuuskraa, V. A.; “Technical Oil Recovery Potential from Residual Oil Zones: Permian Basin”, prepared for U.S. Department of Energy, Office of Fossil Energy - Office of Oil and Natural Gas, February, 2006.

Koperna, G. J., Kuuskraa, V. A.; “Technical Oil Recovery Potential from Residual Oil Zones: Williston Basin”, prepared for U.S. Department of Energy, Office of Fossil Energy - Office of Oil and Natural Gas, February, 2006.

Advanced Resources International; “Basin Oriented Strategies for CO2 Enhanced Oil Recovery: Illinois & Michigan Basins”, prepared for U.S. Department of Energy, Office of Fossil Energy - Office of Oil and Natural Gas, February, 2006.

Advanced Resources International; “Basin Oriented Strategies for CO2 Enhanced Oil Recovery: Williston Basin”, prepared for U.S. Department of Energy, Office of Fossil Energy - Office of Oil and Natural Gas, February, 2006.

Advanced Resources International; “Basin Oriented Strategies for CO2 Enhanced Oil Recovery: Rocky Mountain Region”, prepared for U.S. Department of Energy, Office of Fossil Energy - Office of Oil and Natural Gas, February, 2006.

Advanced Resources International; “Basin Oriented Strategies for CO2 Enhanced Oil Recovery: Onshore Gulf Coast”, prepared for U.S. Department of Energy, Office of Fossil Energy - Office of Oil and Natural Gas, February, 2006.

Advanced Resources International; “Basin Oriented Strategies for CO2 Enhanced Oil Recovery: Permian Basin”, prepared for U.S. Department of Energy, Office of Fossil Energy - Office of Oil and Natural Gas”, February, 2006.

Advanced Resources International; “Basin Oriented Strategies for CO2 Enhanced Oil Recovery: Mid-Continent Region”, prepared for U.S. Department of Energy, Office of Fossil Energy - Office of Oil and Natural Gas, February, 2006.

Advanced Resources International; “Basin Oriented Strategies for CO2 Enhanced Oil Recovery: East & Central Texas”, prepared for U.S. Department of Energy, Office of Fossil Energy - Office of Oil and Natural Gas, February, 2006

Advanced Resources International; “Basin Oriented Strategies for CO2 Enhanced Oil Recovery: Alaska”, prepared for U.S. Department of Energy, Office of Fossil Energy - Office of Oil and Natural Gas, April, 2005.

Advanced Resources International; “Basin Oriented Strategies for CO2 Enhanced Oil Recovery: California”, prepared for U.S. Department of Energy, Office of Fossil Energy - Office of Oil and Natural Gas, April, 2005.

Koperna, G. J., Melzer, L. S., & Kuuskraa, V. A. (2006, January 1). Recovery of Oil Resources From the Residual and Transitional Oil Zones of the Permian Basin. Society of Petroleum Engineers. doi:10.2118/SPE 102972-MS

Abstract

Because of their low to moderate oil saturations, the immobile (but significant) oil resources in the transition and residual oil zones (TZ/ROZ) are not economic to produce using primary/secondary oil recovery techniques. As such, the great majority of domestic oil wells are completed at the first evidence of mobile water (oil-water contact) above the TZ/ROZ. Outside of a small group of forward-looking operators, little is known about the ability to target and produce this large TZ/ROZ resource. However, in the current economic climate and with technology advances, the TZ/ROZ resource offers a new source of domestic oil production. The relatively thick (100s of feet) TZ/ROZ located beneath the traditional main pay zones of Permian Basin oil reservoirs provides an attractive domestic development resource.

Carbon dioxide (CO2) enhanced oil recovery (EOR) is a viable technique for recovering immobile residual oil left behind ("stranded??) after waterflooding. Further, the oil saturation in the TZ/ROZ portion of a reservoir is often similar to the oil saturation left after waterflooding. As such, with progress in CO2 flooding technology and availability of affordable supplies of CO2, the oil in the TZ/ROZ could become an economically viable target.

This paper will provide updates for four key TZ/ROZ projects (two in the Wasson oil field, one in the Seminole San Andres Unit and a fourth at Salt Creek). These pilot projects plus reservoir simulation work by the authors show that this residual oil can be efficiently recovered using CO2-EOR. The paper discusses how two CO2-EOR practices, selective completions and joint development with the main pay zone, would enable the recovery of the TZ/ROZ resource to be optimized. The paper concludes with an assessment of how much resource potential in the TZ/ROZ may hold for future oil development with the Permian Basin.

Full paper available at https://www.onepetro.org

Melzer, L. S., Kuuskraa, V. A., & Koperna, G. J. (2006, January 1). The Origin and Resource Potential of Residual Oil Zones. Society of Petroleum Engineers. doi:10.2118/102964-MS

Abstract

Tectonics and active aquifers beneath oil-bearing reservoirs can be powerful forces in trapping large quantities of residual oil. In regions of the world where basin uplift (or subsidence) has created basinal tilt or where the oil columns are underlain by active aquifers, significant quantities of oil may have been swept from the original oil accumulation. In these situations, the once horizontal producing oil-water contact (OWC) transitions to a tilted interface across the field, creating a new and higher OWC. Below the new and now tilted OWC, there now exists a thick reservoir interval of immobile oil, called the residual oil zone (ROZ).

In the past, the ROZ was only water productive and therefore avoided. Today, with the advent of CO2 EOR and several demonstration projects, this oil zone (often quite comparable in residual oil saturation with the waterflood swept interval in the main pay zone) has been shown to be a technically viable target for additional oil recovery.

In the Permian Basin, OWC tilts have been mapped in many of the oil fields, particularly in the Permian age San Andres and Grayburg reservoirs. Examination of well logs clearly shows the presence of significant ROZs (often with 100's of feet in thickness) below the tilted producing OWC. Throughout the middle portion of the interval, the oil saturation is near residual oil saturation. The oil in place, due to ROZ thickness, is often on par with the original oil in place in the MPZ, representing a large, significant undeveloped oil resource.

This paper discusses the origin and resource potential of ROZs. The paper examines how: 1) regional or local basin tilt; 2) breached and reformed seals; and/or 3) altered hydrodynamic flow fields can form ROZs. Subsequently, the paper examines, using geologic and reservoir modeling, how key oil reservoir and aquifer properties influence the shape, size and resource potential of ROZs.

Full paper available at https://www.onepetro.org

Advanced Resources International, “Development of an Advanced Approach for Next-Generation Integrated Reservoir Characterization” Final Report, DOE Contract No. DE-FC26-01BC15357, April, 2005.

Advanced Resources International, “Development, Testing and Validation of a Neural Model to Predict Porosity and Permeability from Well Logs, Grayburg Formation, McElroy Field, West Texas”, Topical Report, DOE Contract No. DE-FC26-01BC15357, July, 2003.

Stevens, S., Kuuskraa, V., O'Donnell, J.; “Enhanced Oil Recovery Scoping Study”, Final Report, TR-113836, prepared for EPRI Chemicals, Petroleum and Natural Gas Center, Palo Alto, CA, October, 1999.

Kuuskraa, V. A.; “The Status of Potential of Enhanced Oil Recovery”, SPE/DOE 14951, prepared for the Society of Petroleum Engineers and U.S. Department of Energy Joint Symposium on Enhanced Oil Recovery, April 1986.

Full paper available at http://www.onepetro.org.

Doscher, T. M., Kuuskraa, V. A., and Hammershalmb, E. C.; “Analysis of Five Field Tests of Steamdrive Additives”, SPE Paper No. 12057, presented at the Society of Petroleum Engineers 58th Annual Technical Conference and Exhibition, October 1983.

Full paper available at http://www.onepetro.org.

Kuuskraa, V. A.; “Reviving Heavy Oil Reservoirs with Foam and Steam”, Oil and Gas Journal, Volume 80, No. 5, pp. 95-105, 1982. (Co-Author)

To access this article, please go to http://www.ogj.com/index.html. Subscription fees may apply.


Carbon Storage

Enhanced Gas Recovery and CO2 Storage in Coal Bed Methane Reservoirs with N2 Co-Injection, A. Y. Oudinot, D.E. Riestenberg, and G.J. Koperna Jr., Advanced Resources International. Paper prepared and presented at the 13th International Conference on Greenhouse Gas Control Technologies, GHGT-13, 14-18 November 2016, Lausanne, Switzerland

Abstract

Field demonstrations of carbon dioxide (CO2) storage in coal seam reservoirs have suffered greatly from lost injectivity due to coal swelling. The swelling of the coal matrix, due to preferential adsorption of CO2 as compared to methane (CH4), causes a reduction in the coal cleat porosity and a corresponding exponential reduction in cleat permeability, which negatively impacts CO2 injection and, as a result, CO2 storage. This might be the greatest technical hurdle to the commercial deployment of CO2-enhanced coal bed methane (ECBM) and storage operations. To mitigate the impact of CO2 swelling, this work will demonstrate that the co-injection of nitrogen (N2) may offset the swelling effects presented by the CO2 and consequently improve the utilization of injected gas in terms of incremental methane recovery, and determine the overall storage potential that these coal bed reservoirs may provide.

Previous work employing Monte Carlo probabilistic techniques emphasized the impact of pressure dependent permeability which controls the flow, and Langmuir isotherms which control the coal storage capacity, on the storage and ECBM processes. These key parameters were thoroughly studied and defined on a coal rank basis. A parametric study was employed and conducted through reservoir simulation of various injection cases. The results show that low rank coals, thanks to their high porosity, need a minimum amount of N2 to reach optimum conditions. On the other hand, high rank coals, due to their high pore and matrix compressibility, require much more N2 to reach optimum conditions. The optimum methane recovery and sequestration conditions for medium rank coals were found to be highly sensitive to initial porosity values.

Link will be posted when papers are published. For more information on the meeting, visit http://www.ghgt.info/

Carpenter, S. M., & Koperna, G. (2015, August 4). Development of the First Internationally Accepted Standard for Geologic Storage of Carbon Dioxide Utilizing Enhanced Oil Recovery (EOR) Under the International Standards Organization (ISO) Technical Committee TC-265. Society of Petroleum Engineers. doi:10.2118/SPE 178506-MS.

Abstract

The Carbon Capture Utilization & Sequestration (Storage) (CCUS) marketplace is lacking standardization and therefore the ability to allow CCUS projects to be advance as Clean Development Mechanism (CDM) projects as well as to advance to full scale commercialization. An international effort between the United States and Canada, funded by the International Performance Assessment Centre for Geologic Storage of Carbon Dioxide (IPAC-CO2 Research Inc.), and managed by CSA Standards, have developed the first internationally recognized Standard for the geologic storage of carbon dioxide (Z-741). The Z-741 Standard has been adopted by the Standards Council of Canada (SCC) and is available to the American National Standards Institute (ANSI). As a direct result of Z-741, the International Standards Organization (ISO) has created a technical committee to advance the development of comprehensive standards that address CCUS.

International Organization for Standardization (ISO) Technical Committee (TC) 265, Carbon dioxide capture, transportation, and geological storage, recently announced the creation of a new working group (WG) focused on standardization in connection with enhanced oil recovery (EOR) related carbon dioxide (CO2) storage. The new group, WG 6, CO2-EOR, was created at the TC-265 third plenary meeting, held at the China University of Petroleum–Beijing on September 23–25, 2013.

During the meeting, the U.S. and Norway proposed the creation of WG 6 following a presentation on CO2-EOR. The U.S. Technical Advisory Group (TAG) to ISO TC 265, administered by CSA Group, an American National Standards Institute (ANSI) organizational member and accredited standards developer, named the U.S. as convener and Norway as co-convener.

The new working group will focus on standardization efforts associated with low-pressure subsurface oil field operating environments and related CO2 recovery operations, as well as the harmonization of CO2 supplies with EOR operations both on a daily basis and over multi-year operational horizons, among other topics. WG 6 has issued an international call for expert participation in its development of standards and other documents related to CO2 EOR.

This paper will address key issues experienced in the standard development process, which is a technical, consensus-based facilitated process. Membership of the Committee is drawn from experts with full project life cycle knowledge and experience – general interest, operators/industry, regulatory, and consultant/service providers, which represent a balance of stakeholder needs.

Full paper available at https://www.onepetro.org

Wallace, M. et al., 2015. “A Review of the CO2 Pipeline Infrastructure in the U.S.” Report prepared for DOE NETL Contract Number DE-FE0004001 under ESPA Task 200.01.03. DOE/NETL-2014/1681, April 21, 2015.

Available at http://energy.gov/epsa/downloads/review-co2-pipeline-infrastructure-us

Koperna, G.J., Carpenter, S.M., Petrusak, R., Trautz, R., Rhudy, R., and R. Esposito, 12th International Conference on Greenhouse Gas Control Technologies, GHGT-12, Project Assessment and Evaluation of the Area of Review (AoR) at the Citronelle SECARB Phase III Site, Alabama USA, Energy Procedia, Volume 63, 2014, Pages 5971-5985, ISSN 1876-6102, http://dx.doi.org/10.1016/j.egypro.2014.11.632.

Available at http://www.sciencedirect.com/science/article/pii/S1876610214024473

Carpenter, S.M., and G. J. Koperna, 12th International Conference on Greenhouse Gas Control Technologies, GHGT-12, Development of the First Internationally Accepted Standard for Geologic Storage of Carbon Dioxide utilizing Enhanced Oil Recovery (EOR) under the International Standards Organization (ISO) Technical Committee TC-265, Energy Procedia, Volume 63, 2014, Pages 3447-3455, ISSN 1876-6102, http://dx.doi.org/10.1016/j.egypro.2014.11.373.

Available at http://www.sciencedirect.com/science/article/pii/S1876610214021882

Godec, M., Koperna, G., and J. Gale, 12th International Conference on Greenhouse Gas Control Technologies, GHGT-12, CO2-ECBM: A Review of its Status and Global Potential, Energy Procedia, Volume 63, 2014, Pages 5858-5869, ISSN 1876-6102, http://dx.doi.org/10.1016/j.egypro.2014.11.619.

Available at http://www.sciencedirect.com/science/article/pii/S1876610214024345

Godec, M.G., 2013. “Potential Implications on Gas Production from Shale and Coals for Geological Storage of CO2”, prepared for the International Energy Agency (IEA), report: 2013/10, September 2013.

Available at: http://www.ieaghg.org/docs/General_Docs/Reports/2013-10.pdf

Grant, T. C., Morgan, D., Godec, M. L., Lawrence, R., Valenstein, J., & Murray, R. (2012, January 1). NETL CO2 Injection and Storage Cost Model. Carbon Management Technology Conference. doi:10.7122/151027-MS

Abstract

The U.S. Department of Energy's National Energy Technology Laboratory (NETL) has developed a model to estimate the costs of sequestering captured CO2. This model includes costs from initial regional geologic evaluation through site characterization, permitting, injection/MVA operations, postinjection site care to final site closure and transfer to long-term stewardship. Differences in storage costs across different geologic formations are driven by two basic factors: injectivity which determines the number of injection wells drilled to accommodate a given rate of CO2 injection and the volume of CO2 to be sequestered which determines, per in-situ reservoir parameters, the areal extent of the plume and hence the Area of Review of a Class VI well permit. The AoR defines the areal extent of MVA activities which dominates costs during injection and post-injection operations. The basic framework for this model provides costs for compliance with various sections of EPA's Class VI regulation and Subpart RR of the GHG Reporting Program. Cost analysis at two levels is provided by this model: site specific where the modeler can enter their own reservoir and cost data and regional in the form of cost supply curves. A geologic and cost database was developed to support this model. Published analyses of storage cost to date have been very general, providing estimates for site characterization or overall costs but few details. While storage costs are a small percentage of overall CCS costs, they represent a significant investment. Getting to the point of injection operations will take tens of millions of dollars.

Model results indicate that operation/post-closure MVA costs will represent some 70 percent of overall storage costs. Also, the financial mechanisms used to establishing Financial Responsibility prior to permitting may represent a significant cost. A detailed understanding of overall storage costs is critical for investors and policy planners. This model can be combined with a simple pipeline costing model that is part of NETL's current Transport, Storage, and Monitoring Cost Model as well as with NETL's Capture-Transport-Storage pipeline model capable of modeling CO2 pipeline networks. This model can be combined with NETL's Power Supply Financial Model for cost analysis across the CCS value chain.

Full paper available at https://www.onepetro.org

Godec, M., Koperna, G., Petrusak, R. and A. Oudinot, GHGT-11 Proceedings of the 11th International Conference on Greenhouse Gas Control Technologies, 18-22 November 2012, Kyoto, Japan, Assessment of Factors Influencing CO2 Storage Capacity and Injectivity in Eastern U.S. Gas Shales, Energy Procedia, Volume 37, 2013, Pages 6644-6655, ISSN 1876-6102, http://dx.doi.org/10.1016/j.egypro.2013.06.597.

Available at http://www.sciencedirect.com/science/article/pii/S1876610213008400

Kuuskraa, V.A., Godec, M. L., and P. Dipietro, GHGT-11 Proceedings of the 11th International Conference on Greenhouse Gas Control Technologies, 18-22 November 2012, Kyoto, Japan, CO2 Utilization from “Next Generation” CO2 Enhanced Oil Recovery Technology, Energy Procedia, Volume 37, 2013, Pages 6854-6866, ISSN 1876-6102, http://dx.doi.org/10.1016/j.egypro.2013.06.618.

Available at http://www.sciencedirect.com/science/article/pii/S1876610213008618

Kuuskraa, V.A., Dipietro, P. and J. Litynski, GHGT-11 Proceedings of the 11th International Conference on Greenhouse Gas Control Technologies, 18-22 November 2012, Kyoto, Japan, The Synergistic Pursuit of Advances in MMV Technologies for CO2–Enhanced Recovery and CO2 Storage, Energy Procedia, Volume 37, 2013, Pages 4099-4105, ISSN 1876-6102, http://dx.doi.org/10.1016/j.egypro.2013.06.311.

Available at http://www.sciencedirect.com/science/article/pii/S1876610213005547

Koperna, G.J., Kuuskraa, V., Riestenberg, D., Rhudy, R., Trautz, R., Hill, G., and R. Esposito, GHGT-11 Proceedings of the 11th International Conference on Greenhouse Gas Control Technologies, 18-22 November 2012, Kyoto, Japan, The SECARB Anthropogenic Test: Status from the Field, Energy Procedia, Volume 37, 2013, Pages 6273-6286, ISSN 1876-6102, http://dx.doi.org/10.1016/j.egypro.2013.06.556.

Available at http://www.sciencedirect.com/science/article/pii/S1876610213007996

Koperna, G. et al, GHGT-11 Proceedings of the 11th International Conference on Greenhouse Gas Control Technologies, 18-22 November 2012, Kyoto, Japan, Coal-Seq III Consortium: Advancing the Science of CO2 Sequestration in Coal Seam and Gas Shale Reservoirs, Energy Procedia, Volume 37, 2013, Pages 6746-6759, ISSN 1876-6102, http://dx.doi.org/10.1016/j.egypro.2013.06.608.

Available at http://www.sciencedirect.com/science/article/pii/S1876610213008515

Koperna, G. J., & Ferguson, R. C. (2011, January 1). Linking CO2-EOR and CO2 Storage in the Offshore Gulf of Mexico. Offshore Technology Conference. doi:10.4043/SPE 21986-MS

Abstract

The Offshore Gulf of Mexico (GOM) has been endowed with a large oil resource, providing 25% of the United State's daily oil production in 2008. As the shallow water reservoirs mature and decline in productivity, deep water finds have been able to arrest production decline in the Gulf. Now that deep water development appears to have reached a plateau, it is logical to consider secondary and/or tertiary recovery methods for extending the productive lives of these fields, particularly in the numerous more mature shallow water GOM oil fields. Based on the characteristics of these reservoirs, carbon dioxide enhanced oil recovery (CO2-EOR) may hold tremendous potential for recovering what would otherwise be permanently stranded oil and for efficiently storing CO2 in the vertically stacked fault blocks typical of offshore fields. This application also presents synergistic opportunities for beneficially using and permanently storing CO2 captured from anthropogenic sources along the Gulf Coast.

This United States Department of Energy - National Energy Technology Laboratory sponsored study will subdivide the offshore resource base into Federal and State waters, highlighting the methodology employed to assess the applicability of CO2-EOR in extending the productive life of these fields. Key findings will summarize the technically recoverable resource and the ultimate CO2 utilization and storage potential using a water-alternating-gas flood design. The technically recoverable resource will then be further delineated using an economic screening model that applies various oil prices and CO2 costs to establish economic viability. Although the Offshore Gulf of Mexico is a high cost operating area, the opportunity for additional oil recovery and permanent CO2 storage make CO2-EOR a synergistic recovery option.

Full paper available at https://www.onepetro.org

Godec, M., Kuuskraa, V., Van Leeuwen, T., Melzer, L.S., and N. Wildgust, 10th International Conference on Greenhouse Gas Control Technologies,CO2 storage in depleted oil fields: The worldwide potential for carbon dioxide enhanced oil recovery, Energy Procedia, Volume 4, 2011, Pages 2162-2169, ISSN 1876-6102, http://dx.doi.org/10.1016/j.egypro.2011.02.102.

Available at http://www.sciencedirect.com/science/article/pii/S1876610211002992

Esposito, R., Rhudy, R., Trautz, R., Koperna, G. and G. Hill, 10th International Conference on Greenhouse Gas Control Technologies, Integrating carbon capture with transportation and storage, Energy Procedia, Volume 4, 2011, Pages 5512-5519, ISSN 1876-6102, http://dx.doi.org/10.1016/j.egypro.2011.02.537.

Available at http://www.sciencedirect.com/science/article/pii/S1876610211008162

Oudinot, A. Y., Koperna, G. J., Philip, Z. G., Liu, N., Heath, J. E., Wells, A., Young, G.B.C., and Wilson, T. (2011, December 1). CO2 Injection Performance in the Fruitland Coal Fairway, San Juan Basin: Results of a Field Pilot. Society of Petroleum Engineers. doi:10.2118/SPE 127073-PA

Abstract

The Pump Canyon CO2-enhanced coalbed methane (ECBM)/sequestration demonstration in New Mexico has the primary objective of demonstrating the feasibility of CO2 sequestration in deep, unmineable coal seams through a small-scale geologic sequestration pilot. This project is not the first of its kind; several small- or large-scale pilots were already conducted previously in the United States [Allison Unit (Reeves et al. 2003) in the San Juan, Appalachian, and Warrior basins] as well as internationally [the Recopol (Reeves and Oudinot 2002) project in Poland, and the Yubari project in Japan, Canada, and Australia]. Additional pilots are currently under way.

At the project site, a new CO2-injection well was drilled within an existing pattern of coalbed-methane-production wells. Primarily operated by ConocoPhillips, these wells produce from the Late Cretaceous Fruitland coals. CO2 injection into these coal seams was initiated in late July 2008 and ceased in August 2009. A variety of monitoring, verification, and accounting (MVA) methods were employed to track the movement of the CO2 in order to determine the occurrence of leakage. Within the injection well, MVA methods included continuous measurement of injection volumes, pressures, and temperatures. The offset production wells sampled gas-production rates, pressures, and gas composition through CO2 sensors, tracers in the injected CO2, time-lapse vertical seismic profiling, and surface tiltmeter arrays. A detailed study of the overlying Kirtland shale was also conducted to investigate the integrity of this primary caprock. This information was used to develop a detailed geologic characterization and reservoir model that has been used to further understand the behavior of this reservoir.

The CO2-injection pilot has ended with no significant CO2 buildup occurring in the offset production wells. However, a small but steady increase in CO2 and N2 at two of the offset wells may have been an indication of imminent breakthrough. More recent gas samples are, however, showing a decrease in CO2 and N2 content at those wells. This paper describes the project, covering the regulatory process and injection-well construction, the different techniques used to monitor for CO2 leakage, and the results of the modeling work.

Full paper available at https://www.onepetro.org

Petrusak, R. L., Cyphers, S., Bumgardner, S. B., Hills, D., Pashin, J., & Esposito, R. A. (2010, January 1). Saline Reservoir Storage in an Active Oil Field: Extracting Maximum Value From Existing Data for Initial Site Characterization; Southeast Regional Carbon Sequestration Partnership (SECARB) Phase III. Society of Petroleum Engineers. doi:10.2118/139700-MS

Abstract

For large-scale carbon dioxide (CO2) injection and storage, saline formations offer vast storage capacity, often in multiple geologic formations, or multiple storage reservoir horizons within a single formation. Challenges for characterizing CO2 storage reservoirs in specific saline formations may include limited subsurface data, unproven geologic traps and lack of any production infrastructure available for injection and monitoring operations. Active oil fields offer advantages for CO2 sequestration in saline formations that address such challenges. Advantages of active oil fields include proven structural traps and reservoir seals; confirmed saline storage horizons; existing field data including geophysical well logs, seismic data, core data, formation water analyses and reservoir pressure tests; existing infrastructure for access and monitoring; and potential use of CO2 in enhanced oil recovery. Such advantages are substantial, but active oil fields can also present unique hurdles for CO2 storage in saline formations. These include old and incomplete well data and geophysical logs; confirming the integrity of cement through the saline formation and confining unit (if located above the oil reservoir); and remediating existing wells.

The Southeast Regional Carbon Sequestration Partnership (SECARB) Phase III Anthropogenic Test is a large-scale demonstration of integrated CO2 capture, transport and storage planned for Citronelle field, in Mobile County, Alabama.1 Anthropogenic CO2 from a coal-fired electric generating plant, Alabama Power's Plant Barry, will be captured and transported to Citronelle field.2 During 2011 to 2014, up to 182,500 tonnes of CO2 will be injected annually into the Lower Cretaceous Paluxy Formation, a saline formation that contains multiple reservoir sandstones and is located above the oil reservoir. This paper describes the initial characterization effort, which used all available field and regional data, to build a reservoir framework for the Paluxy Formation at Citronelle for initial assessment of injectivity, storage capacity and fate of injected CO2. The initial characterization of the Paluxy Formation demonstrates a successful approach for estimating key saline reservoir parameters including porosity, permeability, sand thickness and continuity from an incomplete existing data set in an active oil field. A robust geologic data collection effort is planned for the CO2 injection and observation wells to be drilled at the Anthropogenic Test site during 2011. The new data will be integrated with the existing Paluxy data set at Citronelle field to validate, refine and expand the initial characterization of the CO2 storage reservoir sandstones.

Full paper available at https://www.onepetro.org

Koperna, G. J., Oudinot, A. Y., McColpin, G. R., Liu, N., Heath, J. E., Wells, A., & Young, G. B. (2009, January 1). CO2-ECBM/Storage Activities at the San Juan Basins Pump Canyon Test Site. Society of Petroleum Engineers. doi:10.2118/SPE 124002-MS

Partial Abstract

The Southwest Regional Partnership on Carbon Sequestration (SWP) is one of seven regional partnerships sponsored by the U.S. Department of Energy (DOE) that collectively includes more than 350 organizations spanning 40 states, three Indian nations, and four Canadian provinces. The objectives are to determine the most suitable technologies, regulations and infrastructure requirements for carbon capture, storage and sequestration in different areas of the country. In Phase I of the partnership program, significant sources of greenhouse gas emissions were inventoried, potential geological sequestration sinks identified, and small-scale sequestration demonstration opportunities developed. Many of these small-scale pilot demonstrations are currently being implemented as part of the Phase II program. One of the three geo-sequestration pilots for the SWP involves CO2injection into a deep, unmineable coalbed at the Pump Canyon site located in the San Juan Basin of northern New Mexico.

At the demonstration site, a new CO2injection well was drilled into the late-Cretaceous Fruitland coals within an existing pattern of coalbed methane production wells. CO2is currently being injected into the coal at pressures not to exceed the permitted injection pressure, and a variety of monitoring, verification and accounting (MVA) methods are employed to track the movement of the CO2. Some of the MVA methods include continuous measurement of injection volumes, pressures and temperatures within the injection well, coalbed methane production rates, pressures and compositions at the offset producer wells, tracers in the injected CO2, time-lapse vertical seismic profiling, surface tiltmeter arrays, a series of shallow monitoring wells with a regular fluid sampling program, and surface measurements of soil compositions, CO2fluxes, tracers, etc. In addition, a detailed geologic characterization and reservoir modeling has been implemented in order to reproduce and understand the behavior of the reservoir. To date, the injection is still on-going and no CO2breakthrough has occurred.

This paper provides a description of the Pump Canyon CO2-ECBM (enhanced coalbed methane) and sequestration demonstration field activities with particular emphasis on the lessons being learned

Full paper available at https://www.onepetro.org

Riestenberg, D. E., Koperna, G. J., Kuuskraa, V. A., Esposito, R. A., Harrison, K. E., Berry, C. R., … Rhudy, R. (2009, January 1). CO2 Sequestration Permitting at the SECARB Mississippi Test Site. Society of Petroleum Engineers. doi:10.2118/SPE121073-MS

Abstract

Mississippi Power Company's Victor J Daniel, Jr. electric generating facility is hosting a United States Department of Energy (USDOE)-sponsored CO2 sequestration demonstration as part of the Southeast Carbon Sequestration Regional Partnership. The goal of the project is to demonstrate safe and secure CO2 storage in a deep saline reservoir. Prior to well drilling and injection operations, the primary focus of the project was on public acceptance and permitting of such activities. Three permits were required for the project, a USDOE-NEPA environmental questionnaire, a Mississippi Oil and Gas Board (MOGB) drilling permit, and a Mississippi Department of Environmental Quality (MDEQ) underground injection control (UIC) permit.

The injection well was permitted under the Environmental Protection Agency's Class V Experimental Technology guidelines through the Mississippi Department of Environmental Quality; however, the well was constructed to Class I (non-hazardous) standards. To our knowledge, this is the first CO2 storage well permitted to Class I standards in the United States and certainly the first in the State of Mississippi. This paper will detail the permitting activities for this demonstration project.

Full paper available at https://www.onepetro.org

Petrusak, R. L., Riestenberg, D. E., Goad, P. L., Schepers, K. C., Pashin, J., Esposito, R. A., & Trautz, R. C. (2009, January 1). World Class CO2 Sequestration Potential in Saline Formations, Oil and Gas Fields, Coal, and Shale: The US Southeast Regional Carbon Sequestration Partnership Has It All. Society of Petroleum Engineers. doi:10.2118/SPE 126619-MS

Abstract

The Southeast Regional Carbon Sequestration Partnership (SECARB), led by the Southern States Energy Board (SSEB) represents 11 southeastern states: Alabama, Arkansas, Florida, Georgia, Louisiana, Mississippi, North Carolina, South Carolina, Tennessee, Virginia and east Texas. The SECARB Partnership region contains multiple regional-scale geologic storage opportunities, which offer sufficient capacity to sequester the region's major point source CO2 emissions for decades. These include deep saline formations, depleted oil and gas fields, organic-rich shale formations, Tertiary-age coal deposits of the northern Gulf of Mexico Basin, and coal deposits of the central Appalachian and Black Warrior Basins.

Depleted oil and gas fields can provide excellent early sites for sequestering CO2 in known porous and permeable reservoirs overlain by proven seal formations (confining units). In addition, many oil fields within the SECARB region offer opportunities for integrated application of CO2 enhanced oil recovery (EOR) and CO2 sequestration, potentially helping to accelerate CO2 storage efforts. Depleted oil and gas fields could provide 29.7 to 34.7 gigatonnes (Gt, billion metric tons) of storage with nearly 24 million barrels incremental oil (otherwise stranded oil) that may be recovered. Sixty percent of this capacity is expected from offshore fields.

Storage potential in deep saline formations is vast, estimated conservatively to range from 2,281 to 9,123 Gt. Recent assessment of one regional saline formation, the Upper Cretaceous age Lower Tuscaloosa Group and equivalent Woodbine Formation, estimates storage capacity of 19.8 to 79.5 Gt. Saline formations require comprehensive geologic characterization of the reservoir properties of the storage formation and the seal characteristics and continuity of potential confining units.

Coal and organic-rich shale have significant adsorptive capacity for CO2 and offer potential CO2 storage with enhanced coalbed methane and shale gas production. Low-rank Tertiary coal of the northern Gulf of Mexico basin offers 20 to 28 Gt of potential storage capacity with an additional 1 to 2 Gt from coal seams of the central Appalachian and Black Warrior basins. However, the reservoir potential of Gulf of Mexico coal seams is largely unproven, whereas the Appalachian and Black Warrior basins host major coalbed methane operations. The CO2 storage capacity of the Barnett Shale in the Fort Worth Basin is estimated to be 19 to 27 Gt. Other shale formations include the Fayetteville Shale of the Arkoma Basin, estimated to have 14 to 20 Gt of capacity, and a range of shale formations that have yet to be assessed in the Black Warrior Basin and Appalachian thrust belt. These include the Conasauga Formation (Cambrian), Devonian shale formations, and the Floyd Shale (Mississippian).

Field validation of CO2 injection and storage is critical for confirming CO2 storage estimates, and are the primary path forward to commercialization. Field tests validate the geologic characterization effort and reservoir models, specifically injectivity, capacity and containment, and advance the state-of-the-art in measurement, monitoring and verification. This paper presents recent updates to the current assessments of CO2 storage capacity for the SECARB region. The paper features the SECARB Partnership's recent Mississippi Saline Formation Injection Test as an example of a successful field test which validates key reservoir properties of one of the region's large capacity saline aquifers and lays the groundwork for the next phase large-scale demonstration of carbon capture with saline aquifer storage

Full paper available at https://www.onepetro.org

Kuuskraa, V.A., and T. Van Leeuwen; “Beyond Wedges: Achieving the Obama Administration’s Goals for Reducing Greenhouse Gas Emissions”, Advanced Resources International, Inc., May 1, 2009.

Koperna, G. J., & Riestenberg, D. E. (2009, January 1). Carbon Dioxide Enhanced Coalbed Methane and Storage: Is There Promise? Society of Petroleum Engineers. doi:10.2118/SPE 126627-MS

Abstract

Since the early 1980s, engineers and geologists have been unlocking the secrets of coal seam gas reservoirs. With time and technology advances, such as multi-lateral horizontal drilling, these reservoirs have contributed mightily to the Nation's gas supply. Many of these prolific reservoirs are maturing and field operators now look to improve incremental recoveries from these natural gas sources. One such method is through the use of carbon dioxide enhanced coalbed methane (CO2-ECBM).

CO2-ECBM is a process by which the gas is injected into a coal seam, it is preferentially adsorbed onto the coal, allowing incremental methane to desorb and be produced. This very unique characteristic of a coal allows it to serve double-duty as both a storage reservoir and the seal. As such, geologic sequestration of carbon dioxide in deep, unmineable coal seams may hold tremendous promise for long-term, secure storage of the greenhouse gases as well as providing incremental methane recovery.

However, with only a handful of CO2 injection pilots having been conducted, it seems more questions are being asked regarding the viability of the process than being answered. This paper will focus on the lessons learned from several large-scale and small-scale tests, framing these results against capacity and injectivity estimation and long-term suitability for various coal types/ranks.

Full paper available at https://www.onepetro.org

Kuuskraa, V.A., Koperna, G.J., Riestenberg, D., and R. Esposito, Greenhouse Gas Control Technologies 9, Using reservoir architecture to maximize CO2 storage capacity, Energy Procedia, Volume 1, Issue 1, 2009, Pages 3063-3070, ISSN 1876-6102, http://dx.doi.org/10.1016/j.egypro.2009.02.085.

Available at http://www.sciencedirect.com/science/article/pii/S1876610209007280

Koperna, G. J., Riestenberg, D., Kuuskraa, V., Esposito, R., Rhudy, R.: “SECARB's Mississippi Test Site: A Field Project Update”, presented at the Seventh Annual Conference on Carbon Capture & Sequestration, Pittsburgh, PA, May 5-8, 2008.

Stevens, S.H.; “Alaska Deep Coal Seam Scoping CO2 Sequestration Evaluation.” West Coast Carbon Sequestration Project, 2007. http://www.westcarb.org.

Oudinot, A. Y., Schepers, K. C., and Reeves, S. R.; “Gas Injection and Breakthrough Trends as Observed in ECBM Sequestration Pilot Projects and Field Demonstrations”, Paper No. 0714, presented at the 2007 International Coalbed Methane Symposium, Tuscaloosa, Alabama, May 21-25, 2007.

Kuuskraa, V.A., and M.L. Godec, “Remediation of Leakage from CO2 Storage Reservoirs”, Advanced Resources International, prepared for IEA Greenhouse Gas R&D Programme, IEA/CON/04/108, January 2007. http://www.ieaghg.org

Kuuskraa, V. A. and Koperna G. J.: “Assessing and Expanding CO2 Storage Capacity in Depleted and Near-Depleted Oil Reservoirs” presented at GHGT-8, Trondheim, Norway, June 19-23, 2006.

Reeves S.R. and Oudinot, A.: “The Allison Unit CO2-ECBM Pilot A Reservoir and Economic Analysis”, 2005 International Coalbed Methane Symposium, Paper 0523, Tuscaloosa, Alabama, May 16-20, 2005.

Reeves S.R. and Oudinot, A.: “The Allison Unit CO2-ECBM Pilot A Reservoir and Economic Analysis”, 2005 International Coalbed Methane Symposium, Paper 0522, Tuscaloosa, Alabama, May 16-20, 2005.

Kuuskraa, V., DiPietro, P., Klara S., and S. Forbes, Future U.S. greenhouse gas emission reduction scenarios consistent with atmospheric stabilization of concentrations, In Greenhouse Gas Control Technologies 7, Elsevier Science Ltd, Oxford, 2005, Pages 1633-1639, ISBN 9780080447049, http://dx.doi.org/10.1016/B978-008044704-9/50190-7. (http://www.sciencedirect.com/science/article/pii/B9780080447049501907)

Stevens, S.H. and Bank, G.; “CO2 Storage Potential of Deep Coal Seams in Oregon and Washington”, WESTCARB Annual Meeting, Portland, Oregon, October 27-28, 2004.

Stevens, S.H.; “Economics of Enhanced Coalbed Methane Recovery”, SPE Applied Technology Workshop, Enhanced Coalbed Methane Recovery and Carbon Sequestration, Denver, Colorado, October 28-29, 2004.

Reeves, S.R., Davis, D.W. and Oudinot, A.Y.: “A Technical and Economic Sensitivity Study of Enhanced Coalbed Methane Recovery and Carbon Sequestration in Coal”, Topical Report, DOE Contract No. DE-FC26-00NT40924, April, 2004.

Taillefert, A. and Reeves S. R.: “Screening Model for ECBM Recovery and CO2 Sequestration in Coal”, Coal-Seq V1.0, Topical Report, DOE Contract No. DE-FC26-00NT40924, June, 2003.

Pekot, L.J., and Reeves, S.R.: “Modeling the Effects of Matrix Shrinkage and Differential Swelling on Coalbed Methane Recovery and Carbon Sequestration”, Paper 0328, Proceedings of the International Coalbed Methane Symposium, Tuscaloosa, Alabama May 5-7, 2003.

Reeves, S.R., Taillefert, A., Pekot, L., and Clarkson, C.: “The Allison Unit CO2 - ECBM Pilot: A Reservoir Modeling Study”, Topical Report, DOE Contract No. DE-FC26-00NT40924, February, 2003.

ARI Reeves, S.R.: “Assessment of CO2 Sequestration and ECBM Potential of U.S. Coalbeds”, Topical Report, DOE Contract No. DE-FC26-00NT40924, February, 2003.

Advanced Resources International, “Modeling Coal Matrix Shrinkage and Differential Swelling with CO2 Injection for Enhanced Coalbed Methane Recovery and Carbon Sequestration Applications”, Topical Report, DOE Contract No. DE-FC26-00NT40924, November, 2002.

Reeves, S.R., and Taillefert, A.: “Reservoir Modeling for the Design of the RECOPOL CO2 Sequestration Project, Poland”, Topical Report, DOE Contract No. DE-FC26-00NT40924, June 2002.

Reeves, S.R., and Stevens, S.H.: “CO2 Sequestration”, World Coal, December, 2000. Stevens, S.H. and Gale, J.; “Geologic CO2 Sequestration May Benefit Upstream Industry”, Oil and Gas Journal, May 15, 2000.

Stevens, S.H.; “Enhanced Coalbed Methane Recovery by Use of CO2”, Journal of Petroleum Technology, p. 62, October, 1999. Stevens, S. H. and Spector, D.; “Enhanced Coalbed Methane Recovery: Worldwide Applications and CO2 Sequestration Potential”, Final Report IEA/CONS/97/27, prepared for the IEA Greenhouse Gas R & D Programme, 1998. Stevens, S. H., Kuuskraa, V. K., Spector, D., and Riemer, P., “CO2 Sequestration in Deep Coal Seams: Pilot Results and Worldwide Potential”, Fourth International Conference on Greenhouse Gas Control Technologies, Interlaken, Switzerland, August 30-September 2, 1998.

Stevens, S.H., Lombardi, T.E., Kelso, B.S., McBane, R.A., and Oldaker, P.; “Geologic and Hydrologic Controls on Coalbed Methane Resources in the Raton Basin”, Proceedings of the 1993 International Coalbed Methane Symposium, Birmingham, Alabama, May 17-21, 1993.


Gas Storage

Reeves, S.R., Pekot, L.J., and Koperna, G.J.: “New and Novel Fracture Stimulation Technologies for the Revitalization of Existing Gas Storage Wells”, Final Report, DOE Contract No. DE-94MC31112, May, 2000.

Reeves, S.R., Pekot, L.J., and Koperna, G.J.: "New and Novel Fracture Stimulation Technologies for the Revitalization of Existing Gas Storage Wells: Tip Screenout Fracturing”, Topical Report, DOE Contract No. DE-94MC31112, April, 2000.

Reeves, S.R., Pekot, L.J., and Koperna, G.J.: "New and Novel Fracture Stimulation Technologies for the Revitalization of Existing Gas Storage Wells: Extreme Overbalanced and High Energy Gas Fracturing”, Topical Report, DOE Contract No. DE-94MC31112, April, 2000.

Reeves, S.R., Pekot, L.J., and Koperna, G.J.: “New and Novel Fracture Stimulation Technologies for the Revitalization of Existing Gas Storage Wells: Liquid Carbon Dioxide with Proppant Fracturing”, Topical Report, DOE Contract No. DE-94MC31112, March, 2000.

Advanced Resources International; “New and Novel Fracture Stimulation Technologies for the Revitalization of Existing Gas Storage Wells:”, Final Report, prepared for U.S. Department of Energy, National Energy Technology Laboratory, Contract No. DE-AC21-94MC31112, and Gas Research Institute, Contract No. 5097-270-4057, December, 1999.

Reeves, S.R., Pekot, L.J., and Koperna, G.J.: “Pulse Fracturing Tests Show Mixed Results”, Oil and Gas Journal, December 6, 1999. Reeves, S.R., Pekot, L.J., Schatz, J.F., Bomar, R.M., Dereniewski, E., and Maddox, T.: “Nonaqueous Fracture Fluids Clean Up Faster”, Oil and Gas Journal, November 29, 1999.

Reeves, S.R., Pekot, L.J., Koperna, G.J., and Ammer, J.R.: “Novel Fracturing Enhances Deliverability”, Oil and Gas Journal, November 15, 1999.

Reeves, S.R., Pekot, L.J., Koperna, G.J., and Ammer, J.R.:“Deliverability Enhancement via Advanced Fracturing Technology in Gas Storage Wells”, SPE 56728, Proceedings of the SPE Annual Technical Conference and Exhibition, Houston, October 3-6, 1999.

Reeves, S.R., Pekot, L.J., Koperna, G.J., and Ammer, J.R.: “Enhancing the Deliverability of Gas Storage Wells via New and Novel Fracture Stimulation Technologies”, Proceedings of the International Gas Research Conference, San Diego, November 8-11, 1998.

Ammer, J., Mercer, J., Mroz, T., Koperna, G.J., Harris, R., “Using Geologic Modeling and Reservoir Simulation to Increase Gas Storage Efficiency: A Case Study”, SPE No. 31002, presented at the SPE Eastern Regional Meeting, September 20-21, 1995, Morgantown, WV.

Advanced Resources International, “Application of New and Novel Fracture Stimulation Technologies to Enhance the Deliverability of Gas Storage Wells”, Topical Report, DOE Contract No. DE-94MC31112, April, 1995.


Other

Godec, M. L. (2009, January 1). Environmental Performance of the Exploration and Production Industry: Past, Present, and Future. Society of Petroleum Engineers. doi:10.2118/SPE 120918-MS

Abstract

This paper builds upon past work to document the technological progress made by the oil and gas exploration and production (E&P) industry and the environmental benefits realized from this progress. The improvements in environmental performance made by the E&P industry is documented, industry and societal trends examined, and technological advances contributing to its performance highlighted. The paper describes how company environmental performance has evolved from a necessary activity to comply with regulatory requirements to a major factor differentiating companies to stakeholders, including customers and the communities within which they operate -- or wish to operate. Several new concepts of environmental performance are introduced, particularly relating to extracting environmental value from existing infrastructure. Finally, the paper concludes by describing the likely key future role the E&P industry will play in addressing arguably the most important environmental issue of our time - global climate change.

Full paper available at https://www.onepetro.org

Godec, M.L., “Estimate of the Potential Economic Benefits from the Leasing and Development of Oil and Gas Resources in OCS Moratoria Areas”, Prepared for U.S. Department of Energy/Office of Fossil Energy, Contract No.: DE-AT01-04FE68467, June 6, 2006.

Godec, M. L., & Johnson, N. L. (2005, January 1). Quantifying Environmental Benefits of Improved Oil and Gas Exploration and Production Technology. Society of Petroleum Engineers. doi:10.2118/SPE-94388-MS

Abstract

This paper discusses the complexities that E&P service companies face in the U.S. as they manage their air compliance program for their base facilities, wellsite operations, and transportation fleets while tackling the enormous amount of federal, state, county, and local air regulations. Examples of point sources (e.g., chemical blending facilities), pollution-control devices (e.g., dust collectors), and fugitive emissions (e.g., cutting sacks of dry chemicals) found within the oilfield services sector are presented, and discussions of air permit or permit exemption requirements are included for each example.

This paper is intended to share best practices for establishing and maintaining an air compliance program, including the tools (e.g., compliance matrix) and systematic techniques for managing air compliance. These practices have application across state boundaries, regardless of the site location. The compliance program includes: 1) determining if a site(s) is currently in compliance with applicable air regulations, permits or permit exemptions, including aspects related to preplanning and scope, whom to involve, audit privilege, and disclosure; 2) bringing a site into compliance once nonconformances have been identified, 3) maintaining compliance even if operational changes such as human factors, equipment, chemicals, or new construction occur, and 4) implementing operational controls to ensure compliance with continual regulatory changes.

Full paper available at https://www.onepetro.org

Advanced Resources International: “Identifying Oil Exploration Leads using Integrated Remote Sensing and Seismic Data Analysis, Lake Sakakawea, Fort Berthold Indian Reservation, Williston Basin”, Final Report, DOE Contract No. DE-FG26-02NT15453, June, 2004.

Godec, M., Kuuskraa, V. A., and Bank, G.; “Future Gulf Supplies: Role of the Federal Government”, Part III of a Three Part Series on the GOM, Oil and Gas Journal, September 2, 2002.

Godec, M., Kuuskraa, V. A., and Kuck, B. T.; “Shallow Water Gulf Oil, Gas Supply: A Glass Half Full or Half Empty?” Part II of a Three Part Series on the GOM, Oil and Gas Journal, July 1, 2002.

Godec, M., Kuuskraa, V. A., and Kuck, B. T.; “How U.S. Gulf of Mexico Development, Finding, Cost Trends Have Evolved” Part I of a Three Part Series on the GOM, Oil and Gas Journal, May 6, 2002.

Advanced Resources International. “Application of Advanced Exploration Technologies for the Development of Mancos Formation Oil Reservoirs, Jicarilla Apache Indian Nation, San Juan basin, New Mexico”, Final Report, DOE Contract No. DE-FG26-00BC15194, March, 2002.

Godec, M.L.; “The Answer to Increasing Environmental Compliance Costs: Regulatory Reform or Technology Advance”, SPE 56495, presented at the 1999 SPE Annual Technical Conference and Exhibition, October 4, 1999.

S. Vikas, B. Baron, M.L. Godec, and D. Ribar; “Evaluation of Eastern Canada Offshore Gas Potential and its Impacts on the Market Share in the North American East Coast”, paper presented at the 1998 SPE Gas Technology Symposium, Calgary, Alberta, Canada, March 15-18, 1998.

Godec, M.L. and Reich, S.; “Gas Price Volatility Seen to be Less of a Problem,” Natural Gas, June 1997.

Brashear, J., Becker, A., Godec, M.L., Crawford, P.; Oil and Gas Reserves Replacement Planning Series, “Why Aren’t More U.S. Companies Replacing Oil and Gas Reserves?” “How to Overcome Difficulties with Reserves Replacement’ and “Analytical Approaches for Reserves Replacement Planning,” Oil and Gas Journal, Volume 95 Issue 9, March 3, 1997.

Bilgesu, H. I., Koperna, G. J., “The Impact of Friction Factor on the Pressure Loss Prediction in Gas Pipelines”, SPE No. 30996, presented at the SPE Eastern Regional Meeting, September 20 - 21, 1995, Morgantown, WV.

Godec, M.L., G.E. Smith, T. Fitzgibbon, D. Linz, G. Pauling; “Characterizing Costs and Benefits of Uncertain Future Regulatory Requirements on the U.S. Natural Gas Industry”, SPE 29696, presented at the SPE/EPA Exploration and Production Environmental Conference, Society of Petroleum Engineers, March 27-29, 1995.

Godec, M.L., G. E. Smith, A. Becker, G. Pauling; “A Method for Characterizing Costs and Benefits of Future Regulatory Requirements on the U.S. Natural Gas Industry”, SPE 30046, presented at the Hydrocarbon Economics Symposium, Society of Petroleum Engineers, March 27-28, 1995.

Stevens, S.H., Kuuskraa, V.K., and Kelafant, J., “Lifting the ANS Export Ban: What is the Impact on California Oil Production?” Report prepared for U.S. Department of Energy, Office of Oil and Natural Gas Policy, Contract No. DE-AC01-93EP79129, 619 p., May 1994.

Godec, M.L., T. Stuart-Paul, B. Kosowski, and G.E. Smith; “Economic Impacts of Alternative Produced Water Treatment and Disposal Practices on Oil and Gas Resources in the Gulf of Mexico”, OTC No. 7404, presented at the 26th Annual Offshore Technology Conference, May 2-5, 1994.

Godec, M.L., B. Kosowski, D.J. Haverkamp, and H.W. Hochheiser; “The Potential Role of Future Environmental Regulations on the Domestic Petroleum Industry”, SPE No. 25833, presented at the SPE Hydrocarbon Economics Conference, March 29-30, 1993.

L.R. Crook and M.L. Godec; “Making Sense of End-Use Gas Price Forecasts”, Natural Gas, Volume 9, No. 4, November, 1992.

Godec, M.L., G.E. Smith, and B. Kosowski; “Impacts of Recent Environmental Initiatives on the Cost of Producing Crude Oil and Natural Gas Supplies”, SPE No. 24555, presented at the SPE Annual Technical Conference and Exhibition, October 4-7, 1992.

Godec, M.L. and K. Biglarbigi; “Economic Effects of Environmental Regulations on Finding and Developing Crude Oil in the U.S.”, Journal of Petroleum Technology, January 1991.

Godec, M.L.; "Potential Cumulative Impacts of Environmental Regulatory Initiatives on U.S. Crude Oil Exploration and Production”, report prepared for U.S. Department of Energy, Assistant Secretary for Fossil Energy, under contract No. DE-AC-01-88FE61679 (Task 3), December 1990.

Kuuskraa, V. A., and Godec, M. L.; “The Replacement Cost of Domestic Crude Oil and Natural Gas Reserves”, SPE Paper No. 18109, prepared for the SPE Annual Technical Conference and Exhibition, Houston, Texas, October 2-5, 1988.

Kuuskraa, V. A.; “Major Tar Sand and Heavy Oil Deposits of the United States”, AAPG Studies in Geology Series #25, 1987. (Co-Author)

Kuuskraa, V. A. and Morra, F., Jr.; “Replacement Costs of Domestic Crude Oil”, AAPG Bulletin, Volume 68, No. 8, p. 498, 1984.


top of page