• Energy Research

Abstract The multiphase flow processes during water injection and flowback in shales are largely affected by its multiscale pore structure, different pore types and complex fluid transport mechanisms. At present, it is difficult to measure shale multiphase flow properties in laboratory. This study presents an upscaling model to derive core-scale relative permeability from pore-scale multiphase simulation using organic matter (OM)/inorganic matter (IOM) pore network models. Gas and water absolute permeabilities on OM/IOM pore network models are determined, and gas-water two-phase imbibition (during water injection) and drainage (during flowback) processes in the IOM pore network model are conducted using the invasion percolation theory. A core-scale model is generated with stochastically distributed IOM/OM patches. The upscaled relative permeabilities are derived by assembling gas-water transport properties in the IOM/OM based on the corresponding pore network simulation results. The upscaling method is validated by comparison with an analytical model during water injection and flowback processes. Furthermore, the impacts of total organic carbon (TOC) content and intrinsic permeability ratio of OM to IOM on the upscaled relative permeabilities are analyzed. The critical TOC content and intrinsic permeability ratio at which OM influences the upscaled relative permeabilities are determined. This study provides an effective upscaling workflow to obtain core-scale gas-water relative permeabilities based on pore-scale modeling considering multiple gas/water transport mechanisms in different pore systems.

Based on microscopic water displacement experiments and numerical simulation results, new pore-scale displacement indexes were established and subsequently used to analyze oil and water flow characteristics and evaluate water displacement effectiveness. Thus, our understanding was deepened of remaining oil extraction by increasing liquid withdrawal and adjusting water-driving streamline at the high water-cut stage. Results show that water displacement is a process by which both pore sweep coefficient and inner-pore displacement coefficient are increasing simultaneously, resulting in the increase of microscopic comprehensive displacement efficiency. Preferential flow exists in the water displacement process. At the high water-cut stage, enlargement of velocity and pressure difference between the dominant and non-dominant flow channel indicates the injected water is channeling along the dominant flow channel, so that pore sweep coefficient grows slowly and even levels off, which slows down the increase of the comprehensive displacement efficiency. An inflection can be seen at remaining oil dispersion curve in high water-cut period which implies low utilization of the injected water and poor water displacement effectiveness. Increasing liquid withdrawal, to some extent, can decrease the pressure gap between the dominant and non-dominant flow channel and hence increase pore sweep coefficient. Adjusting water-drive streamline can greatly increase pore sweep coefficient by reducing the injected water channeling along the dominant flow channel and tapping the remaining oil in non-dominant flow channel, and therefore obtains a better response in improving water displacement efficiency.

Abstract The geothermal heat production from Enhanced Geothermal System (EGS) is influenced by complex thermal-hydraulic-mechanical (THM) coupling process, it is necessary to consider THM coupling effects on utilization efficiency and production performance of EGS. The geothermal reservoir regarded as a fractured porous media consists of rock matrix blocks and discrete fractures. Based on local thermal non-equilibrium theory, a mathematical model and an ideal 3D-EGS numerical model incorporating THM coupling process are established to simulate the heat production process in EGS, and the distribution regularities of pressure, temperature, stress and deformation in geothermal reservoir are analyzed. The results show that the connecting fractures are the main flow paths and the transmission characteristic of reservoir is altered due to displacement of fractures caused by the change of pressure and temperature in reservoir. The main parameters controlling the outlet temperature are also studied by sensitivity analysis. An EGS case from Desert Peak geothermal reservoir is simulated with a 3D stochastically generated fracture model to evaluate EGS heat production performance. The results indicate that heat production time, thermal output and power generation can meet the commercial standard with appropriate reservoir and operation parameters, however, energy efficiency and overall heat recovery remain at low level.

Porous structures of shales are reconstructed based on scanning electron microscopy (SEM) images of shale samples from Sichuan Basin, China. Characterization analyzes of the nanoscale reconstructed shales are performed, including porosity, pore size distribution, specific surface area and pore connectivity. The multiple-relaxation-time (MRT) lattice Boltzmann method (LBM) fluid flow model and single-relaxation-time (SRT) LBM diffusion model are adopted to simulate the fluid flow and Knudsen diffusion process within the reconstructed shales, respectively. Tortuosity, intrinsic permeability and effective Knudsen diffusivity are numerically predicted. The tortuosity is much higher than that commonly employed in Bruggeman equation. Correction of the intrinsic permeability by taking into consideration the contribution of Knudsen diffusion, which leads to the apparent permeability, is performed. The correction factor under different Knudsen number and pressure are estimated and compared with existing corrections reported in the literature. For the wide pressure range under investigation, the correction factor is always greater than 1, indicating the Knudsen diffusion always plays a role on the transport mechanisms of shale gas in shales studied in the present study. Most of the values of correction factor are located in the transition regime, with no Darcy flow regime observed. arXiv admin note: substantial text overlap with arXiv:1410.1921

In order to investigate pressure performance of multiple fractured horizontal wells (MFHWs) penetrating heterogeneous unconventional reservoir and avoid the high computational cost of numerical simulation, a semi-analytical model for MFHWs combining Green function solution and boundary element method has been obtained, where the reservoir is divided into different homogeneous substructures and coupled at interface boundaries by plane source function in a closed rectangular parallelepiped. Hydraulic fractures are assumed uniform flux and dual porosity model is used for natural fractures system. Then the model is validated by compared with analytical solution of MFHWs in a homogeneous reservoir and trilinear flow model, which shows that this model can achieve high accuracy even with a small interface discretization number, and it can consider the radial flow around each hydraulic fractures. Finally, the pressure responses with heterogeneous parameters of reservoirs are discussed including heterogeneous permeability, non-uniform block-length and fracture half-length distribution as well as dual porosity parameters like elastic storage ratio and crossflow ratio.

Abstract This paper presents a new upscaling method to derive the core-scale apparent gas permeability from an improved pore-scale permeability model and experimental data, with more rigorous incorporation of varying gas storage/transport mechanisms in nano/micro pores. First, in use of SEM images of a gas-rich shale field example in Sichuan Basin from our lab, pore network models of inorganic-matter (IOM) and organic-matter (OM) are characterized by using a digital-core technique. Next, an improved pore-scale real gas apparent permeability is modeled rigorously for both IOM/OM, respectively, with 1) bulk gas transport, gas adsorption, surface diffusion, pore-size confined phase behavior, and stress-dependent rock properties and 2) an additional reduction in inorganic pore sizes by water film adhered on pore surfaces. Core-scale permeability is then derived by assembling the permeabilities of stochastically distributed IOM/OM patches with different pore network models properties using the Monte Carlo sampling method. The new core-scale permeability model is validated by pulse-decay permeability experiment. Moreover, the representative elementary volume (REV) size is determined by analyzing the relative standard deviation of apparent gas permeability in cases with different sample sizes. The contributions of different gas transport mechanisms are discussed, and the impacts of stress-dependence for several field examples (i.e., Sichuan, Pierre and Barnett Basins) and water film with varying relative humidity (RH) on core-scale apparent permeability are analyzed. This work provides an effective approach to determine the core-scale shale permeability by directly using pore-scale experimental data, which is a common challenge in the unconventional resources.

Abstract Shale gas reservoirs have received considerable attention for their potential in satisfying future energy demands. Technical advances in horizontal well drilling and hydraulic fracturing have paved the way for the development of shale gas reservoirs. Compared with conventional gas reservoir, adsorbed gas accounts for a large proportion of total gas within shale, so the amount of gas desorbed from the formation has a large impact on the ultimate gas recovery. Recently, efforts toward the thermal recovery of shale oil based on hydraulic fracture heating technology (ExxonMobil's Electrofrac) have made some progress. However, the temperature-dependent adsorption behavior and its major applications of evaluating thermal stimulation as a recovery method have not been thoroughly explored. Additionally, many complicated nonlinear processes coexist in shale formation such as Knudsen diffusion, the pressure dependent phenomenon and non-Darcy flow, presenting a significant challenge for quantifying flow in shale gas reservoir. To investigate the effect of thermal recovery based on hydraulic fracture heating, a fully coupled numerical model of a fractured horizontal well is developed to capture the real gas flow in shale gas reservoir. Discrete fracture, dual continuum media and single porosity media are employed to describe the hydraulic fractures, the stimulated reservoir volume (SRV) region and the matrix, respectively. The model incorporates non-linear flow mechanisms including adsorption/desorption, Knudsen diffusion, non-Darcy flow and pressure dependent phenomenon, as well as heat diffusion processes within the shale reserve. Then, the effectiveness of formation factors on thermal recovery is analyzed. The results show that hydraulic fracture heating can actually enhance shale gas recovery by altering gas desorption behavior, and that this method is more suitable for long-term production. More adsorbed gas can be recovered with increasing simulation temperature. The thermal properties of the shale formation only have limited impacts on the long-term production. The gas production rate is primarily determined by the simulation temperature, matrix adsorption ability, fracture spacing, area of the SRV region, bottom hole pressure (BHP) and reservoir permeability. A shale gas reservoir with a large Langmuir volume and SRV area, relatively small fracture spacing, and a high BHP has the potential for thermal treatment to enhance gas recovery. The fracture temperature, the area of the SRV region and the fracture spacing are the only three factors that can be controlled during the design and execution of thermal treatment in the field.