Phase Behavior And Flow Analysis Of Shale Reservoirs Using A Compositionally-extended Black-oil Approach

Open Access
Nojabaei, Bahareh
Graduate Program:
Petroleum and Natural Gas Engineering
Doctor of Philosophy
Document Type:
Date of Defense:
July 10, 2015
Committee Members:
  • Russell Taylor Johns, Dissertation Advisor
  • Russell Taylor Johns, Committee Chair
  • Turgay Ertekin, Committee Member
  • Luis Ayala, Committee Member
  • James Terry Engelder, Special Member
  • Shale reservoirs
  • phase behavior
  • reservoir flow simulation
  • capillary pressure
Pore sizes are on the order of nanometers for shale and tight rock formations. Such small pores can affect the phase behavior of in-situ oil and gas owing to increased capillary pressure. Not accounting for increased capillary pressure can lead to inaccurate estimates of ultimate recovery. In this research, capillary pressure is coupled with phase equilibrium equations and the resulting system of nonlinear fugacity equations is solved to present a comprehensive examination of the effect of small pores on saturation pressures and fluid properties. The results show, for the first time, that accounting for the impact of small pore throats on PVT properties explains the inconsistent GOR behavior observed in tight formations. The small pores decrease bubble-point pressures and either decrease or increase dew-point pressures depending on which part of the two-phase envelope is examined. To estimate production from shale reservoirs, a simulation model should be designed to account for the effect of high capillary pressure on fluid properties. We have chosen to use a compositionally-extended black-oil approach since it is faster and more robust compared to a fully compositional simulation model. Black-oil fluid properties are calculated by flash calculations of the reservoir fluid. Allowing for a variable bubble-point pressure in black- or volatile-oil models requires a table of fluid properties be extended above the original bubble-point. We calculate continuous black-oil fluid properties above the original bubble-point by adding a fraction of the equilibrium gas at one bubble-point pressure to achieve a larger bubble-point pressure. This procedure continues until a critical point is reached. Unlike other commonly used methods, our approach provides a smooth and continuous pressure-composition curve to the critical point. If another component is added, the model further allows for injection of methane or CO2 to increase oil recovery. Further, the approach allows the use of black-oil or volatile-oil properties for tight rocks where capillary pressure affects hydrocarbon phase behavior. The compositional equations (gas, oil, and water components) are solved directly with principle unknowns of oil pressure, overall gas composition, and water saturation. Flash calculations in the model are non-iterative and are based on K-values calculated explicitly from the black-oil data. The advantage of solving the black-oil model using the compositional equations is to increase robustness of the simulations owing to a variable bubble-point pressure that is a function of two parameters, namely gas content and capillary pressure. Leverett J-functions are used to establish the effective pore size-Pc-saturation relationship. The input fluid data to the simulator are pre-calculated fluid properties as functions of pressure for three fixed pore sizes. During the simulation, at any pressure and saturation, fluid properties are calculated at the effective pore radius by using linear interpolation between these three data sets. Our results show that there is up to a 90% increase in recovery when capillary pressure is included in flash calculations. Reservoir initial pressure, reservoir permeability, initial water saturation, and critical gas saturation are among the factors influencing the increase in recovery due to the effect of capillary pressure.