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Some tight sandstone gas reservoirs contain mobile water, and the mobile water generally has a significant impact on the gas flowing in tight pores. The flow behavior of gas and water in tight pores is different than in conventional formations, yet there is a lack of adequate models to predict the gas production and describe the gas-water flow behaviors in water-bearing tight gas reservoirs. Based on the experimental results, this paper presents mathematical models to describe flow behaviors of gas and water in tight gas formations; the threshold pressure gradient, stress sensitivity, and relative permeability are all considered in our models. A numerical simulator using these models has been developed to improve the flow simulation accuracy for water-bearing tight gas reservoirs. The results show that the effect of stress sensitivity becomes larger as water saturation increases, leading to a fast decline of gas production; in addition, the nonlinear flow of gas phase is aggravated with the increase of water saturation and the decrease of permeability. The gas recovery decreases when the threshold pressure gradient (TPG) and stress sensitivity are taken into account. Therefore, a reasonable drawdown pressure should be set to minimize the damage of nonlinear factors to gas recovery.

Authigenic chlorite, which is frequently found in sandstone, has a controlling effect on the reservoirs in which tight oil is adsorbed during hydrocarbon filling. In this study, the content, occurrence state, timing, mechanism and influence of authigenic chlorite on the micro-occurrence states of tight oil were studied using Thin Section (TS), Fluorescent Thin Section (FTS), X-Ray Diffraction (XRD), Field Emission-Scanning Electron Microscopy (FE-SEM), Environmental Scanning Electron Microscopy (ESEM), and Energy Dispersive Spectroscopy (EDS). The results indicate: (1) a spatial coupling between chlorite development, a brackish water delta front facies depositional environment, and biotite-rich arkosic sandstone. (2) Authigenic chlorite can be divided into three types: grain-coating chlorite, pore-lining chlorite, and rosette chlorite. Chlorite forms after early compaction but before other diagenetic phases, and grows via precipitation from pore waters that contain products released during the dissolution of volcanic rock fragments and biotites. Porewater is also pressure-released from feldspars and mudstone. (3) The micro-occurrence states of tight oil can be divided into five types: emulsion form, cluster form, throat form, thin-film form, and the isolated or agglomerated particle form. (4) During hydrocarbon filling, tight oil mainly occurs on the surface of grain-coating and pore-lining chlorite in the form of a thin film, the granular or agglomerated forms are mainly enriched within the intercrystalline pores within the authigenic chlorite, and the cluster forms are mainly enriched in dissolution pores. Isolated or agglomerated particles of tight oil primarily occur in the intercrystalline pores of the rosette chlorite. (5) The specific surface area and the authigenic chlorite’s adsorption potential of authigenic chlorite control the micro-occurrence of tight oil on the surface of the chlorite and in intercrystalline pores. The adsorption capacity of chlorite lies in the following order: pore-lining chlorite intercrystalline pores > rosette chlorite > chlorite in feldspar dissolution pores > pore-lining chlorite surface > grain-coating chlorite intercrystalline pores > grain-coating chlorite surface.

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Summary A significant amount of associated gas has been produced from shale oil reservoirs in the Ordos Basin, northern China, in recent years, which has provided an opportunity for using low-cost, associated gas in enhanced oil recovery (EOR) projects. However, there are few other reports of EOR projects in shale oil reservoirs using associated gas, and a quantitative evaluation of the technique is needed. Therefore, we conducted associated gas and waterflooding experiments in shale oil samples at constant and gradually increasing injection pressure while monitoring the spatial distribution of movable and residual oil by means of nuclear magnetic resonance (NMR) technology. Before the injection experiments, we performed mercury intrusion tests and measured the NMR transverse relaxation time, T2, of fully saturated samples to characterize the pore-throat size distribution of rock samples. Furthermore, we established a novel and robust mathematical model based on a fractal description of the pore space and a capillary tube model to determine the lower limit of the pore radius of movable oil, rc, during gas- and waterflooding. We observed that the oil recovery factor at a low injection pressure (i.e., 0.6 MPa) during the associated gasflooding was lower than that during waterflooding under both constant pressure injection mode and gradually increasing pressure injection mode. However, the performance of associated gasflooding was greatly improved by increasing the injection pressure. High injection pressure indeed produced a higher oil recovery factor, thinner residual oil film thickness, and smaller rc during associated gasflooding than during waterflooding under both injection modes. These differences in behavior appear to be linked to dissimilarities in flooding mechanisms at high and low injection pressures. Our main conclusion is that associated gasflooding at high injection pressure (i.e., 6 MPa) has a better potential for enhancing the oil recovery factor than waterflooding in shale oil reservoirs.