1. Topic: EOR – Gas Injection

Title: Evaluation of CO2 Injectivity from Waterflood Values

Source: OnePetro - SPE Western Regional Meeting, 27-29 May 2010, Anaheim, California, USA

Summary: This paper presents a method for evaluating the CO2 injection rate from data that should be readily available for a field.

URL: http://www.onepetro.org/mslib/app/Preview.do?paperNumber=SPE-132624-MS&societyCode=SPE


2. Topic: EOR – Surfactant flood

Title: Ensemble Based Optimization of EOR Processes

Source: OnePetro - SPE Western Regional Meeting, 27-29 May 2010, Anaheim, California, USA

Summary: This work is a general procedure for designing an initial starting point for a surfactant flood and water flood optimization.

URL: http://www.onepetro.org/mslib/app/Preview.do?paperNumber=SPE-132626-MS&societyCode=SPE


3. Topic: EOR – Chemical EOR

Title: EOR: Current Status and Opportunities

Source: OnePetro - SPE Improved Oil Recovery Symposium, 24-28 April 2010, Tulsa, Oklahoma, USA

Summary: The paper presents an overview of EOR field projects by reservoir lithology (sandstone, carbonate, and turbidite formations) and offshore versus onshore fields.

URL: http://www.onepetro.org/mslib/app/Preview.do?paperNumber=SPE-130113-MS&societyCode=SPE


4. Topic: EOR – CO2

Title: Carbon Capture and Geological Storage: What are the Big Issues and Opportunities?

Source: AAPG Datapages - AAPG Foundation Distinguished Lecturer Series 2009-2010



CO2/ Gas Injection


Gui, P., Hua, X., Cunha, J.C. and Cunha, L.B., “Economic Analysis for Enhanced CO2 Injection and Sequestration Using Horizontal Wells”, Journal of Canadian Petroleum Technology, Volume 47, Number 11, November, 2008.


            CO2 EOR has become the most promising technology for extracting the most incremental oil after conventional methods.  There is also growing emphasis in the geological sequestration of anthropogenic CO2.  State of the art reservoir simulators can accurately predict the performance of CO2 EOR floods and sequestration projects.  In this paper they are used to assess the use of horizontal wells for injecting CO2.  It is shown that they can substantially increase the injection rate, improving areal sweep and CO2 storage.  As a result the CO2 EOR project or injection period for sequestration are considerably shortened, saving operating expenses and improving the financial present worth.


Behzadi, S.H. and Towler, B.F., “A new EOR Method”, SPE 123866, Presented at the SPE Annual Technical Conference and Exhibition, October 4 – 7, 2009, New Orleans, Louisiana.


            A numerical preprocessing program has been coupled to the STARS chemical flood simulator to predict the incremental oil recovery combining Alkali Surfactant Polymer chemical mix to the conventional WAG CO2 flood.  The simulation was run on data from the South Slattery Field, Minnelusa A reservoir.  The results were quite encouraging.  The mix benefits from high micro and macro sweep efficiencies plus miscible flooding, even for a small ASP slug size. Simulated recoveries were greater than either ASP or CO2 WAG by themselves.


Holtz, M.H., “Geologic CO2 Storage in Oil Fields: Considerations for Successful Sites”, SPE 126198, Presented at the SPE International Conference on CO2 Capture, Storage and Utilization, November 2 – 4, 2009, San Diego, California.


            There is fast increasing interest and research in the capture and sequestration of CO2 (CCS) into geologic structures.  The greatest capacity among the geologic options is injection into brine aquifers. The drawback to the brine aquifer is that the cap is not well known and may not be suitable for the long term storage of CO2.  On the other hand, an oil reservoir, by definition has an impermeable cap and the additional benefit of the value of the oil produced in the storage process.  The most efficient oil storage reservoirs are those with an existing gas saturation, so that the CO2 is displacing gas, rather than brine.


Zhang, Y.P., Sayegh, S., and Huang, S., “Enhanced Oil Recovery by Immiscible WAG”, presented at the Canadian International Petroleum Conference, June 13 – 15, 2006, Calgary, Alberta, Canada.


            A number of the heavy oil reservoirs in Canada are deep and thin, hence uneconomical to apply thermal recovery techniques.  This lab experiment investigated the use of CO2 and enriched flue gas in an immiscible WAG injection process in reservoir cores with 12.4 degree API crude.  In each case, tertiary recovery in the range of 6% was achieved.  It was shown that up to 70% N2 in the flue gas did not reduce the recovery and that the use of a foaming agent with the CO2 was beneficial.


Biello, D., “Enhanced Oil Recovery: How to Make Money from Carbon Capture and Storage Today”, http://www.scientificamerican.com/article.cfm?id=enhanced-oil-recovery&print=true, Scientific American, April 9, 2009


The U.S. has at least 100 such projects like SACROC and 3,100 miles (5,000 kilometers) of CO2 pipelines. All told, companies have injected some 10.8 trillion cubic feet of the greenhouse gas since the 1970s, according to petroleum engineer R. Tim Bradley, Kinder Morgan's president of CO2, to raise the yield from oil fields by some 650,000 extra barrels a day—more than 10 percent of daily U.S. total production.


Berenblyum, R., Calderon, G., Kollbotn, L., and Surguchev, L.M., “Modelling CO2 Injection: IOR Potential after Waterflooding”, SPE 113436, presented at the 2008 SPE Improved Oil Recovery Symposium, Tulsa, Oklahoma, April, 2008.


            An evaluation of the importance of correctly representing the physical effects when modeling miscible or immiscible CO2 injection in sandstones or carbonates, including transfer of CO2 from fractures to matrix involving diffusion and gravity segregation, viscous effects, formation of high and low concentration liquid hydrocarbon phases, change in composition, swelling, and chemical interactions between the CO2 and the formation water or rock.


Tolle, B., Pekot, l., Barnes, D., Grammer, M., and Harrison, W., “EOR Potential of the Michigan Silurian Reefs Using CO2”, SPE 113843, presented at the 2008 SPE Improved Oil Recovery Symposium, Tulsa, Oklahoma, April, 2008.


            The Silurian age Brown Niagaran pinnacle reefs of Michigan were discovered in the 1970s and of the 300 developed, many have produced 5 million barrels of oil or more.  This paper discusses the results of the DOE sponsored field demonstration of the Charlton 30/31 reef and the implications for the basin.  The project utilized 4-D seismic, reservoir simulation and one new well.


Grigg, R.B., and Swec, R.K., “Injectivity Changes and CO2 Retention for EOR and Sequestration Projects”, SPE 110760, presented at the 2008 SPE Improved Oil Recovery Symposium, Tulsa, Oklahoma, April, 2008.


            This study expands the knowledge of the development of CO2 plumes and their subsequent transport and dissolution  into saline geological reservoirs.  Core experiments showed that the injection of CO2 into brine-saturated sandstone and carbonates resulted in brine saturation to from 62 to 82%.  In each test, over 90% of the reduction occurred with less than 0.5 Pore volumes.


Cinar, Y., Bukhteeva, O., Neal, P.R., Allinson, W.G. and Paterson, L., “CO2 Storage in Low Permeability Formations”, SPE 114028, presented at the 2008 SPE Improved Oil Recovery Symposium, Tulsa, Oklahoma, April, 2008.


            The technical and economic factors of utilizing a low permeability reservoir that is near to a high volume source of CO2 are compared to utilizing a higher permeability, but more distant reservoir.  It was determined that for all cases, the cost of transporting the CO2 was less than the cost of extra wells, horizontal wells and added compression.


Juanes, R. and MacMinn, C.W., “Upscaling of Capillary Trapping Under Gravity Override: Application to CO2 Sequestration in Aquifers”, SPE 113496, presented at the 2008 SPE Improved Oil Recovery Symposium, Tulsa, Oklahoma, April, 2008.


            A sharp-interface mathematical model of CO2 migration in saline aquifers is presented that specifically accounts for gravity override and capillary trapping.  The model tracks the shape of the plume during injection an accounts for regional groundwater flow during the post-injection period and accounts for the loss of mobility of the ground water due to the trapping of the CO2.



Heavy Oil/Thermal


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


            This study identifies heavy oil resources in the United States approaching 100 billion barrels of Original Oil in Place.


Bagci, A.S., Olushola, S. and Mackay, E., “Performance Analysis of SAGD Wind-Down Process with CO2 Injection”, SPE 113234, presented at the 2008 SPE Improved Oil Recovery Symposium, Tulsa, Oklahoma, April, 2008.


            The results of the numerical simulation of a number of cases utilizing CO2 injection in the wind-down phase of Steam Assisted Gravity Drainage (SAGD) reservoirs is presented.  It was assumed that CO2 was injected for 25 years following up to 12 years of production.  The results of up to 79% recovery factor proved the feasibility of SAGD wind-down with CO2 injection has high potential for EOR and CO2 storage.


Al-Rabaani, A.S., Blunt, M.J. and Muggeridge, A.H., “Calculation of a Critical Steam Injection Rate for Thermally-Assisted Gas-Oil Gravity Drainage”, SPE 113351, presented at the 2008 SPE Improved Oil Recovery Symposium, Tulsa, Oklahoma, April, 2008.


            Thermal assisted gas-oil gravity drainage (TA-GOGD) has been shown to be a promising new technology for the recovery of heavy oil contained in naturally fractured reservoirs.  Steam is introduced into the reservoir, heating the rock matrix, reducing the oil viscosity and increasing the rate of gravity drainage through the matrix.  A formula is derived to calculate the injection rate of the steam to maximize the production rate.


Tabasinejad, F, Karrat, R. and Vossoughi, S., “Feasibility Study of In-Situ Combustion in Naturally Fractured Heavy Oil Reservoirs”, SPE 103969, Presented at the First International Oil Conference and Exhibition in Mexico, August 13 – September 2, 2006, Cancun, Mexico.


            This study was conducted using a conventional one-dimensional, three phase in-situ reservoir simulator with 6 components, two cracking and three oxidation reaction modified to a fractured model.  Simulation results indicate that the optimum water/oil ratio leads to an increase in the amount of oil recovery and a reduction in the amount of air to be injected.  The next step is to conduct laboratory experiments on selected cores.


Alajmi, A, Algharalb, M. and Gharbi, R., “Heavy Oil Displacement by Thermal Recovery Using Different Horizontal/Vertical Wells Configurations”, SPE 106347, presented at the SPE Technical Symposium of Saudia Arabia Section, May 21 – 23, 2006, Dhahran, Saudi Arabia.


            This study was proposed using the high resolution ECLIPSE reservoir simulator to evaluate different configurations of the use of horizontal steam injectors in combination with vertical producers.  It will investigate overall oil recovery from varying (1) different configurations of horizontal and vertical wells, (2) flood patterns, (3) horizontal well length, and (4) mobility ratios.


Nelson, D.G. and Economides, M.J., “Reserves Are Added By Re-Thinking a 1983 Steamflood Pilot”, SPE 11894, presented at the International Petroleum Technology Conference, December 3 – 5, 2008, Kuala Lumpur, Malaysia.


            The results of a terminated steamflood pilot project (Edison field in California) were reexamined, both the original reservoir simulation and actual field measurements.  It was concluded the pilot was not properly designed and the results not understood.  The effect of gravity drainage was not understood in the industry at that time and the steam injectors were designed incorrectly as only one of the four injectors was receiving steam, while the others injected hot water, 100 feet above the steamflood interval. The reexamination concluded that the field was a good candidate for steam flooding, similar to the larger adjacent Kern River field.


Leaute, R.P. and Carey, B.S., “Liquid Addition to Steam for Enhancing Recovery (LASER) of Bitumen with CSS: Results from the First Pilot Cycle”, Journal of Canadian Petroleum Technology, Volume 46, Number 9, September, 2007.


            Following favorable laboratory results, a pilot project was conducted at the Cold Lake Cyclic Steam Stimulation (CSS) project to add light hydrocarbon (C5+ condensate) 6% of the cycle weight into eight wells on the 7th cycle.  The results showed that the recovered diluent exceeded expectations and was similar to what was injected.  The overall oil recovery was consistent with simulated results.


Doraiah, A., Ray, S. and Gupta, P., “In-Situ Combustion Technique to Enhance Hearvy-Oil Recovery at Mehsana, ONGC – A Success Story”, SPE 105248, Presented at the SPE Middle East Oil and Gas Show and Conference, March 11 – 14, 2007, Kingdom of Bahrain.


            The Cambay Basin in Mehsana, India contains a number of heavy oil fields with API gravity of 15 – 18 and viscosity ranging from 50 – 450 cp.  Due to the low gravity, primary recovery in the Baloi and Santhal fields was quite low, in the 6 – 12% range.  Artificial lift produced mostly water.  In 1991 a pilot in-situ combustion project was conducted.  The flood front produced CO2 and heat which combined to increase the oil mobility.  The pilot was expanded to the full field in 1997 and ultimately is expected to increase the recovery to 39 – 45%.


Al Bahlani, A. and Babadagil, T., “Heavy-Oil Recovery in Naturally Fractured Reservoirs with Varying Wettability by Steam Solvent Co-injection”, SPE 117626, presented ant the International Thermal Operations and Heavy Oil Symposium, October 20 – 23, Calgary, Alberta, Canada.


            Using steam in a deeper, naturally fractured reservoir can produce poor results as the steam loses heat, resulting in a hot water flood that only recovers the oil in the fractures, not the matrix itself.  In this experiment, heptane was added as a solvent to enhance gravity and capillary interaction by reducing viscosity and altering the wettability.  It was shown that the process is very fast, recovers 85 – 90% of the solvent and ultimate recovery was high.


Kumar, M., Satik, C. and Hoang, V., “New Developments in Steamflood Modeling”, SPE 97719, presented that the SPE/PS-CIM/CHOA International Thermal Operations and Heavy Oil Symposium, November 1 – 2, 2005, Calgary, Alberta, Canada.


            It has been demonstrated that the recent improvements in the fine-scale, multi-pattern, geostatistical models of steamflood performance can be achieved when sufficient details are included in the model.  By modeling the Kern River field in California, depicting the near vertical steam override, it is shown that steamflooding does not produce by displacement, rather by gravity drainage.



Chemical Flooding


Wang, D.M., Liu, C.D., Wu, W.X. and Wang, G., “Development of an Ultra-Low Interfacial Tension Surfactant in a System with No-Alkali for Chemical Flooding”, SPE 109017, presented at the 2008 SPE Improved Oil Recovery Symposium, Tulsa, Oklahoma, April, 2008.


            The development and evaluation of a series of betaine amphoteric surfactants which have been recently synthesized is presented in this paper.  The results show that the interfacial tension (IFT) between these surfactants and Daqing crude reach an ultra-low value with little or no alkali.  It can be used in both high and low saline reservoirs at varying temperatures and clay contents.


Flaaten, A.K., Nguyen, Q.P., Pope, G.A. and Zhang, J., “A systematic Laboratory Approach to Low-Cost, High-Performance Chemical Flooding”, presented at the 2008 SPE Improved Oil Recovery Symposium, Tulsa, Oklahoma, April, 2008.


            A technique to quickly and inexpensively assess alternative chemical formulations for ASP EOR is presented.  Instead of expensive, time consuming core studies, aqueous and microemulsion phase behavior tests are applied to a number of surfactants, co-solvents and alkalis with a specific crude.  The best four were confirmed with core tests and produced nearly 100% oil recovery with very little surfactant retention.


Le, V.Q., Nguyen, Q.P. and Sanders, A.W., “A novel Foam Concept with CO2 Dissolved Surfactants”, SPE 113370, presented at the 2008 SPE Improved Oil Recovery Symposium, Tulsa, Oklahoma, April, 2008.


            A solution to the viscous fingering, gravity override, and channeling issues in CO2 EOR floods is presented. It is shown with the analysis utilizing the CMG/STARS simulator that with the addition of a CO2 soluble surfactant, injection costs are much lower, the loss of surfactant onto the rock surface is eliminated, and oil recoveries are much improved.


Weatherill, A., “Surface Development Aspects of Alkali-Surfactant-Polymer (ASP) Flooding, SPE 13397, presented at the International Petroleum Technology Conference, Dec. 7 – 9, 2009, Doha, Qatar.


            This paper discusses the surface requirements for conducting an ASP flood and contrasts it with a conventional production operation.  It points out that all ASP floods are somewhat experimental as you cannot be certain how it will perform in any one specific reservoir.  It will require skills and equipment and a level of cleanliness not found in a conventional flood.  The processing of chemicals and water are more comparable to a food processing operation.


Chen, G.Y., Wu, S.L., Yang, Z.Y., Hou, J.B. and Wang, X.J., “Study of the Effect of Injection Water Quality on the Interfacial Tension of ASP/Crude Oil”, Journal of Canadian Petroleum Technology, Volume 46, Number 2, February, 2007.


            A number of ASP pilots have been successfully applied to the Daqing field in China.  Incremental recoveries of 20% of original oil in place over waterflood recovery were experienced.  This study was conducted to evaluate the effect of water quality on the interfacial tension (IFT) reduction by the surfactant.  A number of inorganic and organic substances were tested.  In general, the inorganic compounds had little effect on the IFT, but the organic compounds did raise the IFT to varying degrees.  A process to control the water quality is presented.


Mohan, K., “Alkaline Surfactant Flooding for Tight Carbonate Reservoirs”, APE 129516, presented at the SPE Annual Technical Conference and Exhibition, October 4 – 7, 2009, New Orleans, Louisiana.


            A laboratory study was conducted to investigate the performance of different AS systems on a very low, high saline reservoir.  A surfactant was identified that achieved low IFT in the high saline, hard formation water.  It changed the wettability of the oiw-wet rocks to slightly water-wet.  Oil recovery in the core was 80%+.  No polymer was identified that could tolerate in high saline content.


Rai, K. Johns, R.T., Lake, L.W. and Delshad, M., “Oil-Recovery Predictions for Surfactant Polymer Flooding”, SPE 124001, presented ant the SPE Annual Technical Conference and Exhibition, October 4 – 7, New Orleans, Louisiana.


            With interest growing on the enhanced recovery from alkali-surfactant polymer (ASP) and surfactant-polymer (SP), there is a need for a faster, more accurate methods to screen and design chemical systems in specific reservoirs.  The SP analysis is particularly complex and time consuming.  This paper presents a spreadsheet based methodology that substantially reduces that time and complexity.


Pu, H. and Xu, Q., “An Update and Perspective on Field-Scale Chemical Floods in Daqing Oilfield, China”, SPE 118746, presented at the SPE Middle East Oil and Gas Show and Conference, March 15 – 18, 2009, Bahrain, Bahrain.


            Chemical EOR, including polymer flooding and alkali-surfactant-polymer flooding has been applied worldwide for 20 years.  However, the only full field success that has been reported is the Daqing field in China, where polymer was first injected in 1996.  It has been expanded field-wide and is calculated to account for 25% of the overall production of Daqing, providing up to 14% recovery of the OOIP.  A number of other chemical systems have had field tests, including ASP, alkali only, micellar-polymer and alkali-polymer.  The AST results in particular showed to technically and economically feasible, estimated to recover 20% OOIP after waterflooding.





Fletcher, A.J.P. and Morrison, G.R., “Developing a Chemical EOR Pilot Strategy for a Complex, Low Permeability Waterflood”, SPE 112793, presented at the 2008 SPE Improved Oil Recovery Symposium, Tulsa, Oklahoma, April, 2008.


            A study of a large, complex, low permeability waterflood project (the world’s largest onshore – Australia’s Barrow Island Windalia reservoir).  A plan was sought to address the highly heterogeneous, high porosity but low permeability, highly saline reservoir.  Initial screening recommended that polymers be considered for sweep improvement and conformance control.  Options were developed for field application of polymers to address reservoir uncertainties and assess further chemical EOR applications and potential field wide application.


Ayirala, S., Doe, P., Curole, M. and Chin, R., “Polymer Flooding in Saline Heavy Oil Environments”, SPE 113396, presented at the 2008 SPE Improved Oil Recovery Symposium, Tulsa, Oklahoma, April, 2008.


            It is standard industry practice in heavier oil fields to utilize a conventional synthetic polyacrylamide polymer to control mobility.  However this compound is salt sensitive and loses viscosity when it comes in contact with highly saline water. With more viscous oil this requires more polymer rendering many projects uneconomical.  This paper investigates the use of sea water or other high TDS brine which permits high viscosity to be reached, while reducing the amount of polymer required.  This will save both capital and operating expense when applied field-wide.


Lalehrokh, F. and Bryant, S.L., “Application of pH-Triggered Polymers for Deep Conformance Control in Fractured Reservoirs”, SPE 124773, presented at the SPE Annual Technology Conference and Exhibition, October 4 – 7, 2009, New Orleans, Louisiana.


            Waterflooding is a common treatment for conventional reservoirs, using water to displace the oil toward the producing wells.  However, in highly heterogeneous reservoirs and in particular, naturally fractured reservoirs, the water preferentially moves through the high permeability zones and fractures, bypassing the oil in the matrix.  A solution is proposed to first inject low viscosity pH triggered polymer.  No triggering agent is required.  Polyacrylic acid microgels can swell a thousand fold as the pH of the surrounding fluids change.  In the laboratory experiments, as little as a one percent concentration the decreased the permeability by a factor of ten.


Al-Muntasheri, G.A., Zitha, P.L.J. and Nasr-El-Din, H.A., “Evaluation of a New Cost-Effective Organic Gel System for High Temperature Water Control”, SPE 11080, presented at the International Petroleum Technology Conference, December 4 – 7, 2007, Dubai, U.A.E.


            Historically, organically crosslinked gels have bee used for  conformance treatments for high temperature due to their thermal stability, typically consisting of a polyacrylamide-based polymer and an organic crosslinker. A new gel system was tested using Polyethyleneimine (PEI) to form ringing gels with polyacrylamide homopolymers (PAM) at temperatures up to 130 degrees centigrade (266 degrees F.). A permeability reduction of 94% was achieved  with concentrations of 7 and 9%.


Li, R.F., Yan, W., Liu, S. Hirasaki, G.J. and Miller, C.A., “Foam Mobility Control for Surfactant EOR”, SPE 113910, presented at the 2008 SPE Improved Oil Recovery Symposium, Tulsa, Oklahoma, April, 2008.


            Foam as a substitute for polymer to control mobility in chemical flooding was first used 28 years ago, but only recently has the mechanism been understood and begun wider use.  The foam is generated in-situ by surfactant alternated with gas injection.  Foam is shown to greatly enhance sweep efficiency in a layered sandpack with a 19:1 permeability ratio.  The layered sandpack was completely swept with 1.3 pore volumes using foam, while a standard waterflood would require 8 pore volumes for the same result.


Pu, H. and Yin, D., “Study of Polymer Flooding in Class III Reservoir and Pilot Test”, SPE 109546, presented at the 2008 SPE Improved Oil Recovery Symposium, Tulsa, Oklahoma, April, 2008.


            Since 1996, field-wide polymer flooding has been conducted on the Class II reservoirs (relatively thick and high permeability) in Daqing field in China.  At this stage of development a lab study of the design and effectiveness of polymer flooding the thinner and less permeable Class III zones was conducted.  Six sets of polymer flood plans were analyzed and tested.  The results showed that a separate-layer injection with different molecular weights provided the highest recovery.  The pilot was begun in the field in 2007 is early results are promising.


Dalrymple, D., Eoff, L. and Everett, D., “Conformance While Fracturing Tight Gas Formations”, SPE 114557, presented at the SPE Tight Gas Completions Conference, June 9 – 11, 2008, San Antonio, Texas.


            As discoveries get smaller and have higher permeability, excess water production after hydraulic fracturing can make a number of wells uneconomical.  This paper discusses conformance-while-fracturing (CWF) techniques to reduce produced water.  The process incorporates a hydrophobically  modified water-soluble polymer (HMWSP) to control the effective permeability to the flow of water without significant changes to the flow of hydrocarbon.