Evaluation of Oil Compressibility Effects on Pressure Maintenance in Naturally Fractured Reservoirs Using Streamline Simulation
- Shusei Tanaka (Waseda University) | Norio Arihara (Waseda University) | Muhammad Ali Al-Marhoun (King Fahd University of Petroleum and Minerals)
- Document ID
- Society of Petroleum Engineers
- International Oil and Gas Conference and Exhibition in China, 8-10 June, Beijing, China
- Publication Date
- Document Type
- Conference Paper
- 2010. Society of Petroleum Engineers
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- 1,017 since 2007
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As naturally fractured reservoirs present wide ranges of geological characteristics and complex flow mechanisms between matrix and fracture, reservoir simulation is highly necessary to properly evaluate production performance. Pressure maintenance by gas and/or water injection is often required in naturally fractured reservoirs to control production GOR and to extract more oil from matrix rock. We studied by simulation particularly about effects of oil compressibility below bubblepoint pressure on pressure maintenance and production performance.
We first developed and validated a 3-phase 3-dimensional dual-porosity model with the streamline method considering dissolved gas, capillary pressure and gravity. The fluid compressibility is a primary parameter that directly affects the reservoir performance. We accounted for compressibility effects with the total compressibility in the 3-D pressure equations, and with the effective density in the 1-D flow equations along streamlines. A flash-calculation algorithm was incorporated to treat the gas and oil phases correctly.
The oil and gas compressibility definitions presented by Perrine, that have been being used conventionally, have inherently a physical inconsistency such that oil compressibility below the bubble-point pressure increases with the increase of density, and that the mass of gas phase remains constant with changing pressures. To correct those, new derivation based on the basic compressibility definition was introduced.
Simulating peripheral water-injection with and without crestal gas-injection, results of pressure and production performance were compared for the new and conventional compressibility formulation. With the new compressibility, higher degrees of effectiveness were demonstrated in pressure maintenance. Gas injection also showed effectiveness in pressure maintenance, though it caused higher production GOR and a faster rise of water cut.
As naturally fractured reservoirs (NFR's) are heterogeneous in fracture developments, it is a challenging issue to maintain production and to enhance recovery by means of secondary and tertiary recovery processes. NFR's often produce at high rates in the early time followed by low rates, leading to low recovery. Water and gas injection are effective for maintaining pressure and displacing oil in both matrix and fracture, but great care needs to be taken to prevent early breakthrough of water and gas.
Christian et al.1 carried out a major field study to determine the then future IOR strategy for Ekofisk Field that is known as a low permeability fractured chalk. They set several gas injection and water injection cases, and confirmed by simulation that the expansion of waterflood and continuation of swing-gas injection would increase oil recovery. Qasem and Ershaghi2 examined effects of fracture-matrix properties, the interporosity flow parameter in particular, on oil recovery with gas injection in NFR's. Using vertical cross-sectional models, they confirmed that spatial heterogeneities in matrix rock significantly influence the recovery, and that optimizing gas injection can minimize re-saturation or re-infiltration of oil at down-structure matrix. Verbrugger and Schulte,3 using a semi-analytical model, predicted three-phase coning behavior for horizontal wells in a NFR that is underlaid with a water zone and undergoes gas injection at crest. They confirmed the very small critical rates for gas and water coning.
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