Compositional Simulation of the Effect of Water Injection on Gas Condensate Reservoir Performance
Abstract
It is well recognized that the liquid dropout in the reservoir from a gas condensate reservoir below dew point pressure does not only reduce the ultimate recovery of gas, but can also reduce the gas well deliverability. Therefore, enhancing the ultimate gas recoveries is the major challenge for reservoir engineers during development of gas condensate reservoir. In this research, the importance of water injection on the performance of gas condensate reservoir was studied through fine gridded compositional simulation models. It was discovered that water drive can significantly increase the ultimate gas recoveries of a gas condensate reservoir. The study did not include the economic analysis. However, comparison of ultimate gas recoveries and field production time of different operations were made for feasibility analysis. The performance of gas condensate reservoir under water injection was found to have similar behavior with increasing injection rate. The injection rate of -50% water injection case showed better pressure maintenance and recovery. Furthermore, in this research, total liquid recovery was increased from 4% for natural depletion to 15.4% for -50% water INJ case throughout the producing life and gas recovery was increased to 84% from 62% by injecting water. The maximum wellhead injection pressure of 4891.5psi was obtained from this study. The ultimate aim of maintaining the reservoir pressure slightly above dew point pressure to avoid producing liquid was achieved. The highest recovery was achieved at the 2122 day of water injection.
Highlights
- Variation in injection rate affects gas condensate recovery
- FOE (Field Recovery Efficiency) indicates gas condensate recovery
- Total liquid produced can be determined using FLPT analysis
- Total volume of gas produced can be determined using the FGPT analysis
Pressure maintenance during water injection can be explained using FPR analysis
How to cite this article:
Ikpeka P, Izuwa N, Omeh C. Compositional Simulation of the Effect of Water Injection on Gas Condensate Reservoir Performance. J Adv Res Petrol Tech Mgmt 2019; 5(1&2): 1-16.
References
study of the Arun field. paper SPE 28749 presented at 1994 SPE Asia Pacific Oil and Gas Conference held
in Melbourne, Australia. 1994.
2. Al Ismail M. Influence of Nanopores on the Transport of Gas and Gas-Condensate in Unconventional Resources. PhD dissertation, Stanford University, Stanford, CA. 2016.
3. Ayala L, Ertekin T, Adewumi M. Study of Gas/Condensate Reservoir Exploitation Using Neurosimulation. Petroleum Transactions, AIME April 2007.
4. Azin R, Sedaghati H, Fatehi R et al. Production assessment of low production rate of well in a supergiant gas condensate reservoir: application of an integrated strategy. Journal of Petroleum Exploration and Production Technology 2018; 9: 543–560. https:// doi.org/10.1007/s13202-018-0491-y.
5. Barnum RS, Brinkman FP, Richardson TW et al. Gas condensate reservoir behavior: productivity and recovery reduction due to condensation. paper SPE 30767 presented at 1995 SPE Annual Technical Conference & Exhibition held in Dallas, U.S. A. 1995.
6. Bengherbia M. Tiab D. Gas-Condensate Well Performance Using Compositional Simulator: A Case Study. In SPE Gas Technology Symposium, Calgary, Canada. 2002.
7. Cason L. Waterflooding increases gas recovery, JPT 1989; 41(10): 1102-1106.
8. Engineer R. Cal Canal Field California: Case History of a Tight and Abnormally Pressured Gas Condensate Reservoir. paper SPE 13650 presented at 1985 SPE California Regional Meeting held in Bakersfield, California. 1985.
9. Thomas FB, Dedora N, Zhou F at al. Optimizing Production from Gas Condensate Reservoirs. The Journal of Canadian Petroleum Technology 1994.
10. Fishlock TP, Probert CJ. Waterflooding of gas condensate reservoirs, SPERE. 1996; 11(4): 245.
11. Henderson GD, Danesh A, Peden JM. An experimental investigation of waterflooding of gas condensate reservoirs and their subsequent blowdown. Journal of Petroleum Science and Engineering 1992; 8(1): 43-58.
12. Henderson GD, Danesh AS, Peden JM. Waterflooding of gas-condensate fluids in cores above and below the dewpoint. SPE Advanced Technology Series 1993; 1(2): 123-129.
13. McCain WD. The properties of petroleum fluids. Penn well Books. 1990.
14. Izuwa NC, Amandi K, Oyoh KB. Optimal Injection time and parametric study on gas condensate recovery. International Journal of Scientific and Engineering Research 2015; 6(4): 985-992.
15. Izuwa NC, Obah B, Appah D. Optimal Recovery of Condensate in Gas Condensate reservoirs through Gas Cycling. 2014.
16. Hwang J. Gas Injection Techniques for Condensate Recovery and Remediation of Liquid Banking In Gas Condensate Reservoirs. Thesis submitted to the University of Texas, Austin, May 2011.
17. Kolbikov SV. Gas-Condensate Recovery for the Low Permeable Sands Gas Cycling Efficiency. paper SPE 136380 presented at 2010 SPE Russian Oil and Gas Conference and Exhibition held in Moscow, Russia. 2010.
18. Moghaddam RN, Jamiolahmady M. Fluid transport in shale gas reservoirs: Simultaneous effects of stress and slippage on matrix permeability. International Journal of Coal Geology 2016; 163: 87-99.
19. Ramadan AH, Shedid AS. Improved material balance equation (MBE) for gas-condensate reservoirs considering significant water vaporization. Egyptian Journal of Petroleum 2018; 27(4): 1209-1214. https://doi.org/10.1016/j.ejpe.2018.05.005.
20. Shi C. Flow Behavior of Gas-Condensate Wells. PhD dissertation, Stanford University, Stanford, CA. 2009.
21. Vo HX. Composition Variation During Flow of Gas-Condensate Wells. MS thesis, Stanford University, Stanford, CA. 2010.
