CO2 Mass Transfer and Oil Replacement Capacity in Fractured Shale Oil Reservoirs: From Laboratory to Field

CO2-based fracturing is widely introduced to stimulate shale oil reservoirs for its multiple advantages. However, the range of CO2 entering the matrix around fractures and CO2-oil replacement capacity between matrix and fractures cannot be fully explained. To address this issue, a radial constant volume diffusion experiment on shale cores was designed in this study, and the pressure drop curve history was matched through numerical model to determine the composition effective diffusion coefficient. A field-scale numerical model was established, in which a series of certain grids were used to explicitly characterize fracture and quantify the prosess of CO2 mass transfer and oil replacement. Based on the field-scale numerical model, the process of shut-in, flow back, and oil production was simulated. The distribution of CO2 in fractured shale oil formation and its impact on crude oil during shut-in stage and flow back stage were investigated. This study concludes that CO2 gradually exchanges the oil in matrix into fractures and improve the fluidity of oil in matrix until the component concentrations of the whole reservoir reaches equilibrium during the shut-in process. Finally, about 30∼35 mole % of CO2 in fractures exchanges for oil in matrix. The range of CO2 entering the matrix around fractures is only 1.5 m, and oil in matrix beyond this distance will not be affected by CO2. During the process of flow back and production, the CO2 in fracture flows back quickly, but the CO2 in matrix is keeping dissolved in oil and will not be quickly produced. It is conclued that the longest possible shut-in time is conducive to making full use of the CO2-EOR mechanism in fractured shale oil reservoirs. However, due to the pursuit of economic value, a shut-in time of 10 days is the more suitable choice. This work can provide a better understanding of CO2 mass transfer mechanism in fractured shale oil reservoirs. It also provides a reference for the evaluation of the shut-in time and production management after CO2 fracturing.

A Novel Mathematical Model for Fracturing Effect Evaluation Based on Early Flowback Data in Shale Oil Reservoirs

For shale oil reservoirs, the horizontal well multistage fracturing technique is mostly used to reform the reservoir in order to achieve economic and effective development. The size of the reservoir reconstruction volume and the quantitative characterization of the fracture system are of great significance to accurately predict the productivity of shale oil wells. There are few flowback models for shale oil reservoirs. To solve this problem, first, a physical model of the simultaneous production of oil, gas, and water in the early flowback stage of shale oil development is established using the material balance equation for a fracture system. Second, the physical model of the underground fracture system is simplified, which is approximately regarded as a thin cylindrical body with a circular section. The flow of the fluid in the fracture system is approximately regarded as radial flow. In this model, the expansion of the fluid and the closure of the fracture are defined as integrated storage coefficients to characterize the storage capacity of the fracture system. Then, the curves illustrating the relationships between the oil-water ratio and the cumulative oil production and between the gas-water ratio and the cumulative gas production are drawn, and the curves are used to divide the flowback stage into an early stage and a late stage because the flowback process of shale oil wells exhibits obvious stage characteristics. Finally, the reservoir reconstruction volume and the related hydraulic fracture parameters are estimated based on the material balance method, and the rationality of the model is verified via numerical simulation. The interpretation results of this novel model are more accurate, making it an effective way to evaluate the hydraulic fracture parameters and transformation effect, and it has guiding significance for the evaluation of the hydraulic fracturing effect in the field.

The Influence of Lamina Density and Occurrence on the Permeability of Lamellar Shale after Hydration

The characteristics of laminae in lamellar shale oil reservoirs have important influences on reservoir parameters, especially permeability. In order to explore the influence of lamina density and occurrence on the permeability of lamellar shale after hydration, we studied the lamellar shale in the Chang 7 member of the Yanchang Formation of Triassic in Ordos Basin. By comparing the permeability of bedding shale and lamellar shale with different densities of laminae, it was found that the permeability anisotropy of lamellar shale was stronger. In the direction parallel to the lamina, the permeability increased approximately linearly with an increase in lamina density. The effect of hydration on rock micropore structure and permeability was studied by soaking shale in different fluids. Most of the microfracture in the lamellar shale was parallel to the lamina direction, and hydration led to a widening of the microfracture, which led to the most obvious increase in permeability parallel to the lamina. Collectively, the research results proved that lamina density, occurrence, and hydration have a significant influence on the permeability anisotropy of lamellar shale.

Toward Controllable Infill Completions Using Frac-Driven Interactions FDI Data

Infill completions have been explored by many operators in the last few years as a strategy to increase ultimate recovery from unconventional shale oil reservoirs. The stimulation of infill wells often causes pressure increases, known as fracture-driven interactions (FDIs), in nearby wells. Studies have generally focused on the propagation of fractures from infill wells and pressure changes in treatment wells rather than observation wells. Meanwhile, studies regarding the pressure response in the observation (parent) wells are mainly limited to field observations and conjecture. In this study, we provide a partialcorrective to this gap in the research.We model the pressure fluctuations in parent wells induced by fracking infill wells and provide insight into how field operators can use the pressure data from nearby wells to identify different forms of FDI, including fracture hit (frac-hit) and fracture shadowing. First,we model the trajectory of a fracture propagating from an infill well using the extended finite element methods (XFEM). This method allows us to incorporatethe possible intersection of fractures independent of the mesh gridding. Subsequently, we calculate the pressure response from the frac-hit and stress shadowing using a coupled geomechanics and multi-phase fluid flow model. Through numerical examples, we assess different scenarios that might arise because of the interactions between new fractures and old depleted fractures based on the corresponding pressure behavior in the parent wells. Typically, a large increase in bottomhole pressure over a short period is interpreted as a potential indication of a fracture hit. However, we show that a slower increase in bottomhole pressure may also imply a fracture hit, especially if gas repressurization was performed before the infill well was fracked. Ultimately, we find that well storage may buffer the sudden increase in pressure due to the frac-hit. We conclude by summarizing the different FDIs through their pressure footprints.

Origin of authigenic albite in a lacustrine mixed-deposition sequence (Lucaogou Formation, Junggar Basin) and its diagenesis implications

Authigenic albites occur widely in clastic reservoirs with important implications for diagenesis and reservoir formation. The middle Permian Lucaogou Formation in the Jimusaer Sag (Junggar Basin, NW China), where major exploration breakthroughs in shale oil have been achieved, reveals a new phenomenon that authigenic albites are abundant in unique mixed carbonate–volcanic–clastic sequences. This has not been reported in the literatures. To fill the knowledge gap, the origin of these authigenic albites and their relationship with dissolution pores (i.e. diagenesis implications) were investigated. Results show that two types (I and II) of authigenic albite were identified within the shale oil reservoirs. Euhedral Type I authigenic albites with 3–10 μm only occur in dolarenite intraclasts and are symbiotic with amorphous dolomite minerals with a pure chemical composition of >99% albite-end-member content. Larger Type II authigenic albites with 10–50 μm are widely distributed in reservoirs, primarily in dissolution pores, and coexist with authigenic dolomite minerals or dolomite overgrowths. Their chemical composition is less pure with anorthite-end-member contents that range from undetectable to 9.77%, with an average of 1.34%. A symbiotic relationship, pure chemical composition, size, and euhedral morphology indicate that Type I authigenic albites precipitated during syngenetic hydrothermal action. However, the morphology of dissolution pores, residual symbiotic “orthoclase”, impure chemical composition and carbon–oxygen isotope indicate that Type II were the products of the dissolution and reprecipitation of “perthite” crystal pyroclasts influenced by acid organic fluids in latter diagenesis. The differential dissolution of “orthoclase” and “albite” components in “perthite” crystal pyroclasts formed enormous intergranular secondary pores in the presence of dolomite minerals in the shale oil reservoirs.