Development of Gas Assisted Gravity Drainage (GAGD) Process for Improved Light Oil Recovery
- D.N. Rao (Louisiana State University) | S.C. Ayirala (Louisiana State University) | M.M. Kulkarni (Louisiana State University) | A.P. Sharma (Louisiana State University)
- Document ID
- Society of Petroleum Engineers
- SPE/DOE Symposium on Improved Oil Recovery, 17-21 April, Tulsa, Oklahoma
- Publication Date
- Document Type
- Conference Paper
- 2004. Society of Petroleum Engineers
- 4.6 Natural Gas, 1.6 Drilling Operations, 5.3.1 Flow in Porous Media, 1.6.9 Coring, Fishing, 4.1.5 Processing Equipment, 5.4.7 Chemical Flooding Methods (e.g., Polymer, Solvent, Nitrogen, Immiscible CO2, Surfactant, Vapex), 5.4 Enhanced Recovery, 5.2.1 Phase Behavior and PVT Measurements, 1.2.3 Rock properties, 5.2 Reservoir Fluid Dynamics, 4.3.4 Scale, 5.4.9 Miscible Methods, 4.5 Offshore Facilities and Subsea Systems, 5.4.1 Waterflooding, 2.4.3 Sand/Solids Control, 5.7.2 Recovery Factors, 4.1.2 Separation and Treating, 5.3.9 Steam Assisted Gravity Drainage, 5.4.2 Gas Injection Methods, 5.3.4 Reduction of Residual Oil Saturation, 5.10.1 CO2 Capture and Sequestration
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Attempting to overcome natural gravity segregation by alternating gas injection with water has yielded better EOR performance in WAG floods than continuous gas injection (CGI) field projects. However, WAG is still a method to ‘combat' the natural phenomenon of gravity segregation. In attempting to resolve one problem of adverse mobility, the WAG process gives rise to other problems associated with increased water saturation in the reservoir including diminished gas injectivity and increased competition to the flow of oil. The disappointing field performance of WAG floods with oil recoveries in the range of 5-10% is a clear indication of these limitations.
In order to find an effective alternative to WAG, we have initiated the development of the Gas-Assisted Gravity Drainage (GAGD) process. Unlike WAG, the GAGD process takes advantage of the natural segregation of injected gas from crude oil in the reservoir. Although gravity-stable gas floods have long been practiced in selected dipping reservoirs and pinnacle reefs, this project is aimed at a systematic development of a recovery process that would be widely applicable to different reservoir types in both secondary and tertiary modes.
The GAGD process consists of placing a horizontal producer near the bottom of the payzone and injecting gas through existing vertical wells used in prior waterfloods. As the injected gas rises to the top to form a gas zone, oil and water drain down to the horizontal producer. The new GAGD process is being developed using a three-pronged approach: (1) Design and construction of a scaled physical model to demonstrate process feasibility and to investigate and understand the interplay of capillary, gravitational and viscous forces. (2) Process optimization by determining miscibility pressures and compositions through the use of the Vanishing Interfacial Tension (VIT) technique. (3) The process demonstration at reservoir conditions by conducting horizontal WAG floods and vertical GAGD floods in 2-meter long cores. This paper will present the GAGD concept and its advantages over WAG and a summary of the experimental evidence collected so far.
Status of Gas Injection Projects
Within the last twelve years the miscible CO2 projects have increased from 52 in 1990 to 66 in 2002 and their production during the same time period has almost doubled from 95,000 BPD to 187,400 BPD. These data indicate that while the production (and number) of CO2 miscible projects has increased steadily over the last two decades, all other gas injection projects (CO2 immiscible, N2 and flue gas) have declined or become extinct except for the hydrocarbon miscible projects. The production from miscible hydrocarbon gas injection projects in the US has steadily increased from 55,386 BPD in 1990 to 124,500 BPD in 2000 in spite of their decreasing numbers. However, this trend was reversed in 2002 when the production from hydrocarbon gas floods fell to 95,300 BPD, perhaps due to the increasing price of natural gas. The overall effect is that the share of production from gas injection EOR in the US has almost doubled from 23% in 1990 to 44.5% in 2002. This clearly demonstrates the growing commercial interest that the US oil industry has in gas injection EOR projects. The relatively high price of natural gas and the additional benefit of carbon sequestration tip the scales in favor of CO2 for future gas injection projects.
Current Practice by Industry
The viscosity of gases injected, whether CO2 or hydrocarbons, is generally less than one-tenth of that of the oil at reservoir conditions making mobility control one of the biggest factors in a successful gas injection project. Research is ongoing on foams and gels to viscosify the solvents. However, these techniques, still of experimental nature, are not accepted as a part of current miscible flood technology. Hence, the WAG process, first proposed by Caudle and Dyes1 in 1958, has remained the default option for mobility control in horizontal gas floods.
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