Numerical Modelling of Gas Production and CO2 Injection in Tight Shale Reservoirs for Enhanced Gas Recovery

Abstract

Natural gas production from shales has become exceedingly important in satisfying the ever-growing global energy demands. This unconventional hydrocarbon system is globally abundant, with large technically recoverable resources reported in China (1115 tcf), Argentina (802 tcf), US (665 tcf) and Canada (573 tcf). Commercial exploitation of shale resources has led to a shale energy revolution in the last decade. Successful implementation of large-scale horizontal drilling and hydraulic fracturing techniques made this possible and is attributed to collaborative efforts by the natural gas industry (notably Mitchell Energy) and the U.S. Department of Energy (DOE) from the 1980s. A typical gas shale system is a blend of organic-rich deposition and complex mineralogy that forms a fine-grained clastic sedimentary rock with a unique geological framework where the shale independently exists as source, trap and reservoir. Low intrinsic matrix permeability (e.g. 0.1 μD for Huron shales) coupled with structural heterogeneity and complex pore networks complicates fluid transport and storage within the formation and poses tremendous challenges to technical evaluation and effective development. Technological advances in hydraulic stimulation of shale reservoirs have caused a fundamental shift to the exploration-and-production industry. These unconventional reservoirs typically have extremely low matrix permeability (10 to 100 nD) and exhibit gas stored both in free and adsorbed form. Gas flows from the nanopores in the matrix to the hydraulic fractures and then to the horizontal wells. This transport of gas comprises several flow mechanisms as investigated by a large number of scientists and engineers over many years. The first part of the project deals with numerical modelling of shale gas production. Paper I and Paper II presents a mathematical 1D+1D model which involves a high-permeable fracture extending from a well perforation, through symmetrically surrounding shale matrix with low permeability. Gas in the matrix occurs in the form of adsorbed material attached to kerogen (modeled by a Langmuir isotherm) and as free gas in the nano-pores. The pressure gradient towards the fracture and well perforation causes the free gas to flow. With pressure depletion, gas desorbs out of the kerogen into the pore space and then flows to the fracture. When the pressure has stabilized, desorption and production stop. The production of shale gas and mass distributions indicate the efficiency of species transfer between fracture and matrix. The model is then scaled, and production is characterized by applying input parameters from experimental and field data in the literature. Properties of fracture and matrix are varied systematically to understand the role of the fracture matrix interaction during production. Paper I investigate the main controlling factors during continuum flow regime in shale gas production in the context where well-induced fractures, extending from the well perforations, improve reservoir conductivity and performance. While Paper II focuses on the transition in non-Darcy flow regimes near fracture-matrix interfaces using mathematical modelling. Especially, we investigate conditions at which these effects vanish, and Darcy flow assumptions become reasonable. Investigated Non-Darcy mechanisms include apparent permeability, Knudsen diffusion, gas desorption and Forchheimer flow. Paper I showed that the production behavior can be scaled and described according to the magnitude of two characteristic dimensionless numbers: the ratio of diffusion time scales in shale and fracture 𝛼, and the pore volume ratio between the shale and fracture domains 𝛽. The product 𝛼𝛽 expresses how much time it takes to diffuse the gas in place through the fracture to the well compared to the time it takes to diffuse that gas from the matrix to the fracture. For 𝛼𝛽 ≪ 1 the residence time in the fracture is of negligible importance and fracture properties such as shape, width and permeability can be ignored. However, if 𝛼𝛽 ≈ 1 the residence time in the fracture becomes important and variations in all those properties have significant effects on the solution. Scaling the model in Paper II showed that recovery of gas depends on two dimensionless number that incorporates geometry relations, time scales of flow, intrinsic parameters of the porous media, non-Darcy constants, adsorption and boundary conditions. The dimensionless numbers define respectively if 1) the fracture or matrix limit the gas production rate 2) if non-Darcy flow is significant in the fracture or matrix. When one of the media limit production, the non-Darcy flow in the other medium has reduced importance and can be excluded from the model. Non-Darcy flow is important if it limits flow in the medium limiting the production. By checking the magnitude of the selected dimensionless numbers, the modelling approach can be determined in advance and significant computational time can be saved. The second part of the project (Paper III and Paper IV) deals with CO2 injection in shale gas reservoirs for enhanced recovery. Although current technological advancements in horizontal drilling and fluid fracturing have contributed to primary production, only 5 – 10 % of the original gas in place (OGIP) is estimated to be recovered economically leaving a high potential for enhanced recovery methods. The gas stored by sorption in the shale matrix is estimated to account for 20 – 80 % of the total gas fraction. Desorption is triggered by pressure reduction and/or presence of a favorably adsorbing gas. Experimental studies have demonstrated that shale kerogen/organic matter has higher affinity for CO2 than methane, CH4, which opens possibilities for carbon storage and new production strategies. Paper III presents a new multicomponent adsorption isotherm which is coupled with a flow model for evaluation of injection-production scenarios. The isotherm is based on the assumption that different gas species compete for adsorbing on a limited specific surface area. Rather than assuming a capacity of a fixed number of sites or moles this finite surface area is filled with species taking different amount of space per mole. The final form is a generalized multicomponent Langmuir isotherm. Experimental adsorption data for CO2 and CH4 on Marcellus shale are matched with the proposed isotherm using relevant fitting parameters. The isotherm is first applied in static examples to calculate gas in place reserves, recovery factors and enhanced gas recovery potential based on contributions from free gas and adsorbed gas components. The isotherm is further coupled with a dynamic flow model with application to CO2-CH4 substitution for CO2-ESGR, assuming only gas phase exists in the system. The paper presents the feasibility and effectiveness of CO2 injection in tight shale formations in an injectionproduction setting representative of lab and field implementation and compare with regular pressure depletion. Paper IV reviews the state of research on CH4 and CO2 sorption in shale. It presents the interaction of CO2 and CH4 with shale rocks and discuss the dependence of gas sorption on shale properties including organic matter content, kerogen type, mineralogy, moisture and temperature as well as shale selectivity for either species. Dynamic CO2-CH4 exchange studies are also summarized together with the geochemical and mechanical impact of gas sorption in shales. We note that most experimental work is still performed on crushed samples rather than whole cores. Also, CO2 is preferentially adsorbed over CH4 when both species co-exist in shale. Both gases are in supercritical state at typical reservoir conditions. Especially CO2 adsorption is not well described by standard isotherm models in this state.