Phase behavior is important in the calculation of hydrocarbons in place and in the flow of phases through the rocks. Pore sizes can be 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 because of increased capillary pressure. Not accounting for increased capillary pressure in small pores can lead to inaccurate estimates of ultimate recovery, and of saturation pressures. In this paper, 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 densities. Binary mixtures of methane with heavier hydrocarbons and a real reservoir fluid from the Bakken shale are considered.The results show that accounting for the impact of small pore throats on pressure/volume/temperature (PVT) properties explains the inconsistent gas/oil-ratio (GOR) behavior, high flowing bottomhole pressures, and low gas-flow rate observed in the tight Bakken formation. 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. Large capillary pressure also decreases the oil density in situ, which affects the oil formation volume factor and ultimate reserves calculations. A good history match for wells in the middle Bakken formation is obtained only after considering a suppressed bubblepoint pressure. The results show that the change in saturation pressures, fluid densities, and viscosities is highly dependent on the values of interfacial tension (IFT) (capillary pressure) used in the calculations.

Shale oil and gas resources contribute significantly to the energy production in the U.S. Greenhouse gas emissions come from combustion of fossil fuels from potential sources of power plants, oil refineries, and flaring or venting of produced gas (primarily methane) in oilfields. Economic utilization of greenhouse gases in shale reservoirs not only increases oil or gas recovery, but also contributes to CO2 sequestration. In this paper, the feasibility and efficiency of gas injection approaches, including huff-n-puff injection and gas flooding in shale oil/gas/condensate reservoirs are discussed based on the results of in-situ pilots, and experimental and simulation studies. In each section, one type of shale reservoir is discussed, with the following aspects covered: (1) Experimental and simulation results for different gas injection approaches; (2) mechanisms of different gas injection approaches; and (3) field pilots for gas injection enhanced oil recovery (EOR) and enhanced gas recovery (EGR). Based on the experimental and simulation studies, as well as some successful field trials, gas injection is deemed as a potential approach for EOR and EGR in shale reservoirs. The enhanced recovery factor varies for different experiments with different rock/fluid properties or models incorporating different effects and shale complexities. Based on the simulation studies and successful field pilots, CO2 could be successfully captured in shale gas reservoirs through gas injection and huff-n-puff regimes. The status of flaring gas emissions in oilfields and the outlook of economic utilization of greenhouse gases for enhanced oil or gas recovery and CO2 storage were given in the last section. The storage capacity varies in different simulation studies and is associated with well design, gas injection scheme and operation parameters, gas adsorption, molecular diffusion, and the modelling approaches.

Phase behavior is important in the calculation of hydrocarbons-in-place and in the flow of phases through the rocks. Pore sizes can be 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 in small pores can lead to inaccurate estimates of ultimate recovery, and saturation pressures. In this paper, 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 densities. Binary mixtures of methane with heavier hydrocarbons, and a real reservoir fluid from the Bakken shale are considered. The results show that understanding the impact of small pore throats on PVT properties explains the inconsistent GOR behavior, high flowing bottomhole pressures, and low gas flow rate observed in the tight Bakken formation. 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. For the pore radius of 10 nanometers in the Bakken shale, the calculations show that there is more than a 900 psi reduction in the bubble-point pressure as the reservoir is depleted. Further, reduction of oil density due to small pores can impact the formation oil factor and ultimate reserve calculations. The results also show that the change in saturation pressures and fluid densities are very dependent on the values of the interfacial tension used in the calculations.

Pore sizes are typically on the order of nanometers for many shale and tight rock oil reservoirs. Such small pores can affect the phase behavior of in situ oil and gas owing to large capillary pressure. Current simulation practice is to alter the unconfined black-oil data for a fixed mean pore size to generate confined black-oil data with a depressed bubble-point pressure. This approach ignores compositional effects on interfacial tension and the impact of pore-size distribution (PSD) with variable phase saturations on capillary pressure and phase behavior.In this paper, we develop a compositionally-extended black-oil model where we solve the compositional equations (gas, oil, and water components) directly so that black-oil data are a function of gas content in the oleic phase and gas-oil capillary pressure. The principle unknowns in the variable bubble-point fully-implicit formulation are oil pressure, overall gas composition, and water saturation. Flash calculations in the model are noniterative 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; gas content and capillary pressure. Leverett J-functions measured for the Bakken reservoir are used to establish the effective pore size-P c -saturation relationship, where the effective pore size depends on gas saturation. The input fluid data to the simulator, e.g. interfacial tension (IFT), phase densities and viscosities, are pre-calculated as functions of pressure from the Peng-Robinson equation of state (PREOS) 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. In the current simulator, the reservoir permeability is enhanced to allow for opening of the fracture network by hydraulic fractures. We compare the results of the compositionally-extended black oil model with those of a fully-implicit eight-component compositional model that we have also developed. The results for the Bakken reservoir show that including PSD in the model can increase estimated recoveries by nearly 10%. We also examine the sensitivities of production to various parameters, such as wettability and critical gas saturation.

In this study, a fast and robust compositionally extended black-oil simulation approach is developed, which is capable of including the effect of large gas-oil capillary pressure for first and multi-contact miscible, and immiscible gas injection. The simulation approach is used to model primary depletion and gas flooding in a high-permeability reservoir using a five-spot flow pattern for different reservoir pressures. The comparison with fully-compositional model shows good agreement. For an initially undersaturated reservoir with both injection and production wells pressures above the original bubble-point pressure, gas evolves near the injection well and it later breaks through the production well as produced gas is injected. Additionally, the primary depletion and huff-n-puff gas injection in tight shale reservoirs by using the compositionally extended black-oil model indicates that the effect of large gas-oil capillary pressure on recovery becomes smaller as reservoir pressure is higher. Finally, a dynamic gas-oil relative permeability correlation that accounts for the compositional changes owing to the produced gas injection is introduced and applied, and its effect on oil recovery is examined.