Compositional Simulation of Hydraulically Fractured Tight Formation Considering the Effect of Capillary Pressure on Phase Behavior
- Nithiwat Siripatrachai (Pennsylvania State University) | Turgay Ertekin (Pennsylvania State University) | Russell T. Johns (Pennsylvania State University)
- Document ID
- Society of Petroleum Engineers
- SPE Journal
- Publication Date
- August 2017
- Document Type
- Journal Paper
- 1,046 - 1,063
- 2017.Society of Petroleum Engineers
- Phase Behavior, Unconventional Reservoir, Reservoir Simulation, Fractured Reservoir, Capillary Pressure
- 7 in the last 30 days
- 540 since 2007
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Compositional reservoir simulation plays a vital role in the development of conventional and unconventional reservoirs. Two major building blocks of compositional simulation are phase-behavior and fluid-transport computations. The oil and gas reserves and flow of reservoir fluids are strongly dependent on phase behavior. In conventional reservoirs, capillary pressure is relatively small and is typically ignored in phase-behavior calculations. The approach is accepted as the norm to perform phase-equilibria calculation to estimate the oil and gas in place and fluid properties. However, large capillary pressure values are encountered in tight formations, such as shales, and therefore, its effects should not be ignored in phase-equilibria calculations. Many parameters and uncertainties contribute to the accuracy of the estimation and simulation results. In this research, the focus is on the effect of capillary pressure, and neglecting the effects of capillary pressure on phase behavior can lead to an inaccurate estimation of original oil in place (OOIP) and original gas in place (OGIP) as well as recovery performance because of the inherent assumption of equal phase pressures in the phase-equilibria calculation. Understanding of the effect of capillary pressure on phase behavior in tight reservoirs is by no means complete, especially by use of compositional simulation for hydraulically fractured reservoirs.
In this paper, we develop a new compositional reservoir simulator capable of modeling discrete fractures and incorporating the effect of capillary pressure on phase behavior. Large-scale natural and hydraulic fractures in tight rocks and shales are modeled with a technique called the embedded-discrete-fracture model (EDFM), where fractures are modeled explicitly without use of local-grid refinement (LGR) or an unstructured grid. Flow of hydrocarbons occurs simultaneously within similar and different porosity types. Capillary pressure is considered in both flow and flash calculations, where simulations also include variable pore size as a function of gas saturation to accurately reflect temporal changes in each gridblock during the simulation. We examine the effect of capillary pressure on the OOIP and cumulative oil production for different initial reservoir pressures (above and below the bubblepoint pressure) on Bakken and Eagle Ford fluids. The importance of capillary pressure on both flow and flash calculations from hydraulically fractured horizontal wells during primary depletion in fractured tight reservoirs by use of two fluid compositions is demonstrated.
Phase-behavior calculations show that bubblepoint pressure is suppressed, allowing the production to remain in the single-phase region for a longer period of time and also altering phase compositions and fluid properties, such as density and viscosity of equilibrium liquid and vapor. The results show that bubblepoint suppression is larger in the Eagle Ford shale than for Bakken. On the basis of the reservoir fluid and model used for the Bakken and Eagle Ford formations, when capillary pressure is included in the flash, we found an increase in OOIP up to 4.1% for the Bakken crude corresponding to an initial reservoir pressure of 2,000 psia and 46.33% for the Eagle Ford crude corresponding to an initial pressure of 900 psia. Depending on the initial reservoir pressure, cumulative primary oil production after 1 year increases because of the capillary pressure by approximately 9.0 to 38.2% for an initial reservoir-pressure range from 2,000 to 3,500 psia for Bakken oil and 7.2 to 154% for an initial reservoir-pressure range from 1,500 to 3,500 psia for Eagle Ford oil. The recovery increase caused by capillary pressure becomes more significant when reservoir pressure is far less than bubblepoint pressure. The simulation results with hydraulically fractured wells give similar recovery differences. For the two different reservoir settings in this study, at initial reservoir pressure of 5,500 psia, cumulative oil production after 1 year is 3.5 to 5.2% greater when capillary pressure is considered in phase-behavior calculations for Bakken. As initial reservoir pressure is lowered to 2,500 psia, the increase caused by capillary pressure is up to 28.1% for Bakken oil for the case studied. Similarly, at initial reservoir pressure of 2,000 psia, the increase caused by capillary pressure is 21.8% for Eagle Ford oil.
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