Eagle Ford Huff-and-Puff Gas Injection Pilot: Comparison of Reservoir Simulation, Material Balance and Real Performance of the Pilot Well
- Daniel Orozco (Schulich School of Engineering, University of Calgary) | Alfonso Fragoso (Schulich School of Engineering, University of Calgary) | Karthik Selvan (Nexen Energy ULC) | Roberto Aguilera (Schulich School of Engineering, University of Calgary)
- Document ID
- Society of Petroleum Engineers
- SPE Annual Technical Conference and Exhibition, 24-26 September, Dallas, Texas, USA
- Publication Date
- Document Type
- Conference Paper
- 2018. Society of Petroleum Engineers
- 5.4.2 Gas Injection Methods, 5 Reservoir Desciption & Dynamics, 5.4 Improved and Enhanced Recovery, 3 Production and Well Operations, 2 Well completion, 5.4.1 Waterflooding, 4.6 Natural Gas, 5.5 Reservoir Simulation, 1.6.6 Directional Drilling, 1.6 Drilling Operations, 5.8.4 Shale Oil, 5.5.8 History Matching, 2.4 Hydraulic Fracturing
- upside-down fluid distribution, pilot well, frac hits, Eagle Ford shale, huff and puff gas injection
- 18 in the last 30 days
- 308 since 2007
- Show more detail
- View rights & permissions
|SPE Member Price:||USD 8.50|
|SPE Non-Member Price:||USD 25.00|
A comparison is made of real data from an Eagle Ford huff-and-puff (H&P) gas injection pilot with reservoir simulation and tank material balance calculations. The comparison is good and supports the conclusion that oil recovery from the Eagle Ford (and likely other shales) can be increased significantly with the use of H&P.
The study is based on the container methodology: for H&P to work, the injected gas and the insitu oil in the shale must be contained vertically and laterally following hydraulic fracturing. Containment is critical for the success of H&P. Vertical and lateral containment exist in the Eagle Ford as demonstrated previously (Fragoso et al., 2015) with the upside-down distribution of fluids: natural gas is at the bottom of the structure, condensate in the middle and oil at the top. Two different matching and forecasting approaches are used in this study: reservoir simulation and tank material balance calculations.
Results show a good history match of primary recovery and secondary recovery by H&P in the pilot well. The history match is good in the case of both reservoir simulation and tank material balance calculations. Once a match is obtained, the simulation and material balance are used to forecast secondary recovery over a period of 10 years with sustained H&P injection of dry gas. Results indicate that dry gas H&P can increase oil recovery from the Eagle Ford shale significantly. Under favorable conditions, oil recovery can be doubled and even tripled over time compared with the primary recovery. The addition of heavier ends to the H&P gas injection can increase even more oil recoveries, putting them on par with conventional reservoirs. The benefit of H&P occurs both in the case of immiscible and miscible gas injection. The H&P benefits can likely be also obtained in other shale reservoirs with upside-down containers for dry gas, condensate and oil.
The novelty of the work is the combined use of reservoir simulation and tank material balance calculations to match performance of an H&P gas injection pilot in the Eagle Ford shale of Texas. The conclusion is reached that oil recoveries can be increased significantly by H&P.
|File Size||2 MB||Number of Pages||19|
Egboga, N.U., Mohantym K. K., and Balhoff, M. T., 2017. A Feasibility Study of Thermal Stimulation in Unconventional Shale Reservoirs. Journal of Petroleum Science and Engineering, Volume 154, 576 - 588, June 2017. https://doi.Org/10.1016/j.petrol.2016.10.041.
Fragoso, A., Selvan, K., and Aguilera, R., 2018a. Breaking a Paradigm: Can Oil Recovery From Shales Be Larger Than Oil Recovery From Conventional Reservoirs? The Answer Is Yes! Presented at the SPE Canada Unconventional Resources Conference held in Calgary, Alberta, Canada, 13 – 14 March 2018. SPE 189784.
Fragoso, A., Trick, M., Harding, T., Selvan, K. and Aguilera, R. 2018b. Coupling of Wellbore and Surface Facilities Models with Reservoir Simulation to Optimize Recovery of Liquids from Shale Reservoirs. In press: SPE Reservoir Evaluation and Engineering. Presented at the SPE Canada Unconventional Resources Conference, Calgary, Alberta, Canada, 15 – 16 February 2017. SPE 185079.
Gamadi, T., Sheng, J., Soliman, M., Menouar, H., Watson, M. and Emadibaladehi, H. 2014. An Experimental Study of Cyclic CO2 Injection to Improve Shale Oil Recovery. Society of Petroleum Engineers. Presented at the SPE Improved Oil Recovery Symposium, Tulsa, Oklahoma, USA, 12 – 16 April 2014. SPE 169142.
Honarpour, M., Nagarajan, N., Orangi, A., Arasteh, F., Yao, Z. 2012. Characterization of Critical Fluid, Rock and Rock Fluid Properties-Impact on Reservoir Performance of Liquid-rich Shales. Presented at the SPE Annual Technical Conference and Exhibition, San Antonio, Texas, USA, 8-10 October. SPE 158042.
Li, L. and Sheng, J. 2017. Numerical analysis of cyclic CH4 injection in liquid-rich shale reservoirs based on the experiments using different-diameter shale cores and crude oil. Journal of Natural Gas Science and Engineering, Volume 39, 1 – 14, January 2017. https://doi.Org/10.1016/j.jngse.2017.01.017.
Piedrahita, J., Lopez Jimenez, B. and Aguilera, R. 2018. Generalized Methodology for Estimating Stress-Dependent Properties in a Tight Gas Reservoirs and Extension to Drill-Cuttings Data. In press: SPE Reservoir Evaluation and Engineering. Presented at the Unconventional Resources Technology Conference, San Antonio, Texas, USA, August 1 – 3, 2016. URTeC 2461443/SPE 189972.
Ramirez, J., and Aguilera, R., 2016. Factors Controlling Fluid Migration and Distribution in the Eagle Ford Shale. SPE Journal of Reservoir Evaluation and Engineering, Volume 19, No. 03, 403 - 414. http://dx.doi.org/10.2118/171626-PA.
U.S. Energy Information Administration. 2018. Petroleum & Other Liquids, Tight Oil Production Estimates by Play. May 2018. https://www.eia.gOv/petroleum/data.php#crude (accessed May 31, 2018).