Long-Time Diversion in Surfactant-Alternating-Gas Foam Enhanced Oil Recovery From a Field Test
- William R. Rossen (Delft University of Technology) | Alonso Ocampo (Equión Energía) | Alejandro Restrepo (Equión Energía) | Harold D. Cifuentes (Equión Energía) | Jefferson Marin (Equión Energía)
- Document ID
- Society of Petroleum Engineers
- SPE Reservoir Evaluation & Engineering
- Publication Date
- February 2017
- Document Type
- Journal Paper
- 1 - 7
- 2017.Society of Petroleum Engineers
- modeling, diversion , field trial, foam injectivity, foam enhanced oil recovery
- 66 in the last 30 days
- 443 since 2007
- Show more detail
- View rights & permissions
|SPE Member Price:||USD 10.00|
|SPE Non-Member Price:||USD 30.00|
The ability of foam to divert gas flow during a long period of gas injection in a surfactant-alternating-gas (SAG) foam process is important for the economics of foam-diversion processes for enhanced oil recovery (EOR). Here, we interpret field data from the foam test in the Cusiana field in Colombia (Ocampo et al. 2013). In this test, surfactant was injected into a single layer that had been taking approximately half the injected gas before the test; then, gas injection resumed into all layers. On the basis of the size of the surfactant slug injected and estimates of adsorption and of water saturation in the foam in situ, we estimate that the treated region extended approximately 5.3 m from the injection well; fortunately, the results to follow are not sensitive to this estimate. On the basis of the change in injection logs before the test and at Day 5 of the test, when approximately 30 pore volumes (PVs) of gas (relative to the volume of the treated zone) had been injected, foam still reduced gas mobility in the treated layer to approximately 11% of its pretrial value. We base this estimate on the decrease of injection into the treated layer and the increase of injection into the other layers; the results are consistent among the layers. After 35 and 152 days of injection (220 and 1,250 treatment PV of gas injected), foam reduced gas mobility in the treated zone to approximately 26 and 50% of its value before the test, respectively.
This result indicates that foam continued to reduce mobility by a modest amount even after long injection of gas. On the other hand, foam did weaken progressively as it dried out. Foam models in which foam remains strong at irreducible water saturation would greatly overestimate foam effectiveness at long times in this test.
In this test, the large volume of gas had quickly penetrated far beyond the edge of the surfactant bank. Mobility in the foam-treated region in this test, after passage of many treatment PVs of gas injection, mimics that very near the injection well in a process with a larger slug of surfactant.
|File Size||300 KB||Number of Pages||7|
Boeije, C. S. and Rossen, W. R. 2014 Gas Injection Rate Needed for SAG Foam Processes to Overcome Gravity Override. SPE J. 20: 49–59. SPE-166244-PA. http://dx.doi.org/10.2118/166244-PA.
Cheng, L., Reme, A. B., Shan, D. et al. 2000. Simulating Foam Processes at High and Low Foam Qualities. Presented at the SPE/DOE Symposium on Improved Oil Recovery, Tulsa, USA, 3–5 April. SPE-59287-MS. http://dx.doi.org/10.2118/59287-MS.
Computer Modelling Group. 2006. STARS User’s Guide, Version 2006. Calgary.
Computer Modelling Group. 2015. STARS User’s Guide, Version 2015. Calgary.
Gauglitz, P. A., Friedmann, F., Kam, S. I. et al. 2002. Foam Generation in Homogeneous Porous Media. Chem. Eng. Sci. 57: 4037–4052. http://dx.doi.org/10.1016/S0009-2509(02)00340-8.
Hoefner, M. L., Evans, E. M., Buckles, J. J. et al. 1995. CO2 Foam: Results From Four Developmental Field Trials. SPE Res Eng 10: 273–281. SPE-27787-PA. http://dx.doi.org/10.2118/27787-PA.
Khatib, Z. I., Hirasaki, G. J., and Falls, A. H. 1988. Effects of Capillary Pressure on Coalescence and Phase Mobilities in Foams Flowing Through Porous Media. SPE Res Eng 3: 919–926. SPE-15442-PA. http://dx.doi.org/10.2118/15442-PA.
Lake, L. W., Johns, R. T., Rossen, W. R. et al. 2014. Fundamentals of Enhanced Oil Recovery, Richardson, Texas: Society of Petroleum Engineers.
Leeftink, T. N., Latooij, C. A., and Rossen, W. R. 2015. Injectivity Errors in Simulation of Foam EOR. J. Petroleum Sci. Eng. 126: 26–34. http://dx.doi.org/10.1016/j.petrol.2014.11.026.
Ma, K., Lopez-Salinas, J. L., Puerto, M. C. et al. 2013. Estimation of Parameters for the Simulation of Foam Flow Through Porous Media, Part 1: The Dry-Out Effect. Energy & Fuels 27: 2363–2375. http://dx.doi.org/10.1021/ef302036s.
Namdar Zanganeh, M., Kam, S. I., LaForce, T. C. et al. 2011. The Method of Characteristics Applied to Oil Displacement by Foam. SPE J. 16: 8–23. SPE-121580-PA. http://dx.doi.org/10.2118/121580-PA.
Ocampo, A., Restrepo, A., Cifuentes, H. et al. 2013. Successful Foam EOR Pilot in a Mature Volatile Oil Reservoir Under Miscible Gas Injection. Presented at the International Petroleum Technology Conference, Beijing, 26–28 March. IPTC-16984-MS. http://dx.doi.org/10.2523/IPTC-16984-MS.
Patzek, T. W. 1996. Field Applications of Steam Foam for Mobility Improvement and Profile Control. SPE Res Eng 11: 79–86. SPE-29612-PA. http://dx.doi.org/10.2118/29612-PA.
Persoff, P., Pruess, K., Benson, S. M. et al. 1990. Aqueous Foams for Control of Gas Migration and Water Coning in Aquifer Gas Storage. Energy Sources 12: 479–497. http://dx.doi.org/10.1080/00908319008960220.
Pickup, G. E., Jin, M., and Mackay, E. J. 2012. Simulation of Near-Well Pressure Build-up in Models of CO2 Injection. Presented at the European Conference on the Mathematics of Oil Recovery, Biarritz, France, 10–13 September. Paper B34. http://dx.doi.org/10.3997/2214-4609.20143238.
Rossen, W. R. 1996. Foams in Enhanced Oil Recovery. In Foams: Theory, Measurements and Applications, ed. R. K. Prud’homme and S. Khan, 413–464. New York: Marcel Dekker.
Rossen, W. R., Zeilinger, S. C., Shi, J.-X. et al. 1999. Simplified Mechanistic Simulation of Foam Processes in Porous Media. SPE J. 4: 279–287. SPE-57678-PA. http://dx.doi.org/10.2118/57678-PA.
Rossen, W. R. and Boeije, C. S. 2015. Fitting Foam-Simulation-Model Parameters to Data: II. Surfactant-Alternating-Gas Foam Applications. SPE Res Eval & Eng 18 (2): 273–283. SPE-165282-PA. http://dx.doi.org/10.2118/165282-PA.
Schramm, L. L. (ed.) 1994. Foams: Fundamentals and Applications in the Petroleum Industry, ACS Advances in Chemistry Series No. 242. Washington, DC: American Chemical Society.
Shan, D. and Rossen, W. R. 2004. Optimal Injection Strategies for Foam IOR. SPE J. 9: 132–150. SPE-88811-PA. http://dx.doi.org/10.2118/88811-PA.
Skauge, A., Aarra, M. G., Surguchev, L. et al. 2002. Foam Assisted WAG: Experience From the Snorre Field. Presented at the SPE/DOE Improved Oil Recovery Symposium, Tulsa, USA, 13–17 April. SPE-75157-MS. http://dx.doi.org/10.2118/75157-MS.
Turta, A. T. and Singhal, A. V. 1998. Field Foam Applications in Enhanced Oil Recovery Projects: Screening and Design Aspects. Presented at the SPE International Conference and Exhibition, Beijing, 2–6 November. SPE-48895-MS. http://dx.doi.org/10.2118/48895-MS.
Zhdanov, S. A., Amiyan, A. V., Surguchev, L. M. et al. 1996. Application of Foam for Gas and Water Shut-off: Review of Field Experience. Presented at the SPE European Petroleum Conference, Milan, Italy, 22–24 October. SPE-36914-MS. http://dx.doi.org/10.2118/36914-MS.
Zhou, Z. H. and Rossen, W. R. 1995. Applying Fractional-Flow Theory to Foam Processes at the “Limiting Capillary Pressure”. SPE Advanced Technology Series 3: 154–162. SPE-24180-PA. http://dx.doi.org/10.2118/24180-PA.