Video: 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)
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- Society of Petroleum Engineers
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- 2018. Copyright is retained by the author. This presentation is distributed by SPE with the permission of the author. Contact the author for permission to use material from this video.
- 5.4 Improved and Enhanced Recovery, 5.5.8 History Matching, 5.8.4 Shale Oil, 1.6.6 Directional Drilling, 1.6 Drilling Operations, 5 Reservoir Desciption & Dynamics, 5.4.1 Waterflooding, 2.4 Hydraulic Fracturing, 2 Well completion, 5.4.2 Gas Injection Methods, 5.5 Reservoir Simulation, 4.6 Natural Gas, 3 Production and Well Operations
- huff and puff gas injection, Eagle Ford shale, upside-down fluid distribution, frac hits, pilot well
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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.