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.

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.

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In this paper, we investigate the effect of pore size heterogeneity on fluid composition distribution of multicomponent-multiphase hydrocarbons and its subsequent influence on mass transfer in shale nanopores. The change of multi-contact minimum miscibility pressure (MMP) in heterogeneous nanopores was investigated. We used a compositional simulation model with a modified flash calculation, which considers the effect of large gas–oil capillary pressure on phase behavior. Different average pore sizes for different segments of the computational domain were considered and the effect of the resulting heterogeneity on phase change, composition distributions, and production was investigated. A two-dimensional formulation was considered here for the application of matrix–fracture cross-mass transfer and the rock matrix can also consist of different segments with different average pore sizes. Both convection and molecular diffusion terms were included in the mass balance equations, and different reservoir fluids such as ternary mixture syntactic oil, Bakken oil, and Marcellus shale condensate were considered. The simulation results indicate that oil and gas phase compositions vary in different pore sizes, resulting in a concentration gradient between the two adjacent pores of different sizes. Given that shale permeability is extremely small, we expect the mass transfer between the two sections of the reservoir/core with two distinct average pore sizes to be diffusion-dominated. This observation implies that there can be a selective matrix–fracture component mass transfer as a result of confinement-dependent phase behavior. Therefore, the molecular diffusion term should be always included in the mass transfer equations, for both primary and gas injection enhanced oil recovery (EOR) simulation of heterogeneous shale reservoirs.

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Molecular diffusion plays an important role in oil and gas migration and transport in tight shale formations. However, there are insufficient reference data in the literature to specify the diffusion coefficients within a porous media. This study aims at calculating diffusion coefficients of shale gas, shale condensate, and shale oil at reservoir conditions with CO2 injection for EOR/EGR. The large nano-confinement effects including large gas-oil capillary pressure and critical property shifts on diffusion coefficient are examined. An effective diffusion coefficient that describes the diffusion behavior in a tight porous solid is estimated by using tortuosity-porosity relations as well as the measured shale tortuosity from 3D imaging techniques. The results indicated that nano - confinement could affect the diffusion behavior through altering the phase properties, such as phase compositions and densities. Compared to bulk phase diffusivity, the effective diffusion coefficient in a porous shale rock is reduce by 102 to 104 times as porosity decreases from 0.1 to 0.03.

In this paper, phase behaviours and mass‐transfer mechanisms of a Bakken light crude oil‐CO2 system are studied. A series of PVT tests of the light crude oil‐CO2 system are conducted to measure CO2 solubilities, oil‐swelling factors, and CO2‐saturated oil densities at different equilibrium pressures and the actual reservoir temperature of Tres = 56.0 °C. Five CO2 diffusion tests in the light crude oil are performed at five different initial test pressures (Pi = 4.1, 5.2, 6.3, 7.7, and 9.0 MPa) and Tres = 56.0 °C by applying the pressure decay method (PDM). The graphical method (GM) is used to analyze the measured test pressure versus time data of each diffusion test and determine CO2 average diffusivity in the light crude oil. It is found that the so‐called density‐driven natural convection can occur in the CO2‐saturated light crude oil as its measured density is much higher than that of the dead light crude oil. Three distinct periods of CO2 dissolution into the light crude oil are identified: the natural convection‐dominated period (I), the transition period, and the molecular diffusion‐dominated period (II). The determined CO2 effective diffusivities (Deff) in Period I and CO2 molecular diffusivities (D) in Period II from the GM are in the ranges of 0.28–1.75 × 10−6 m2/s and 0.87–1.94 × 10−9 m2/s at the initial test pressures of Pi = 4.1–9.0 MPa, respectively. Finally, it is also found that the constant Z‐factor approximation used in the GM may cause a relatively large error in the determination of Deff or D.