No abstract

Surface diffusion plays a key role in gas mass transfer due to the majority of adsorbed gas within abundant nanopores of organic matter in shale gas reservoirs. Surface diffusion simulation is very complex as a result of high reservoir pressure, surface heterogeneity, and nonisothermal desorption in shale gas reservoirs. In this paper, a new model of surface diffusion for adsorbed gas in shale gas reservoirs is established, which is based on a Hwang model derived under a low pressure condition and considers the effect of adsorbed gas coverage under high pressure. Additionally, this new model considers the effects of surface heterogeneity, isosteric sorption heat, and nonisothermal gas desorption. Results show that (1) the surface diffusion coefficient increases with pressure and temperature, while it decreases with activation energy and gas molecular weight; (2) contributions of viscous flow, Knudsen diffusion, and surface diffusion to the total gas mass transfer are varying during the development of shale gas reservoirs, which are mainly controlled by nanopore-scale and pressure; (3) in micropores (pore radius of <2 nm), the contribution of surface diffusion to the gas mass transfer is dominant, up to 92.95%; in macropores (pore radius of >50 nm), the contribution is less than 4.39%, which is negligible; in mesopores (2 nm < pore radius < 50 nm), the contribution is between micropores and macropores.

Production from shale-gas reservoirs plays an important role in natural-gas supply in the United States. Horizontal drilling and multistage hydraulic fracturing are the two key enabling technologies for the economic development of these shale-gas reservoirs. It is believed that gas in shale reservoirs is mainly composed of free gas within fractures and pores and adsorbed gas in organic matter (kerogen). It is generally assumed in the literature that the monolayer Langmuir isotherm describes gas-adsorption behavior in shale-gas reservoirs. However, in this work, we analyzed four experimental measurements of methane adsorption from the Marcellus Shale core samples that deviate from the Langmuir isotherm, but obey the Brunauer-Emmett-Teller (BET) isotherm. To the best of our knowledge, it is the first time to find that methane adsorption in a shale-gas reservoir behaves similar to multilayer adsorption. Consequently, investigation of this specific gasdesorption effect is important for accurate evaluation of well performance and completion effectiveness in shale-gas reservoirs on the basis of the BET isotherm. The difference in calculating original gas in place (OGIP) on the basis of both isotherms is discussed. We also performed history matching with one production well from the Marcellus Shale and evaluated the contribution of gas desorption to the well's performance. History matching shows that gas adsorption obeying the BET isotherm contributes more to overall gas recovery than gas adsorption obeying the Langmuir isotherm, especially at early time in production. This work provides better understanding of gas desorption in shale-gas reservoirs and updates our current analytical and numerical models for simulation of shale-gas production.

Summary Hydraulic fracturing is a dominant technology in unconventional resources development. Recent advances in fracture-diagnostic tools and fracture-propagation models make it necessary to model fractures with complex geometries in reservoir-simulation studies. In this paper, we present an efficient method to model fractures with complex geometries with reservoir simulators. Through nonneighboring connections (NNCs), an embedded discrete-fracture modeling (EDFM) formulation is applied to reservoir simulators to properly model fractures with complex geometries such as fracture networks and nonplanar hydraulic fractures. We demonstrate the accuracy of the approach by performing a series of case studies with two commercial reservoir simulators and comparing the results with local-grid-refinement (LGR) models and a semianalytical solution. The limitations of the model are also discussed. In addition, the results show its computational efficiency as the complexity of fractures increases. We also present two numerical case studies to demonstrate the applicability of our method in naturally fractured reservoirs. The nonintrusive application of the EDFM allows insertion of the discrete fractures into the computational domain and the use of original functionalities of the simulators without having access to the source code of the simulators. It may be easily integrated into existing frameworks for unconventional reservoirs to perform sensitivity analysis, history matching, and production forecasting.

Advancements in horizontal drilling with hydraulic fracturing have enabled commercial oil production from Bakken tight oil reservoirs. However, the primary recovery factor remains very low (less than 15%), resulting in the high volume of oil remaining in place. Hence, it is extremely important to investigate the application of enhanced oil recovery methods. Carbon dioxide (CO2) injection as a huff-n-puff process is a preferred approach to improve oil recovery in tight reservoirs. In this work, we present the effect of CO2 molecular diffusion and performed a series of sensitivity studies to quantify the impacts of reservoir properties such as permeability and fracture properties such as fracture half-length, fracture conductivity, number of fractures, and operation parameters such as CO2 injection rate, injection time, soaking time, number of cycle of CO2 huff-n-puff and CO2 diffusivity on the CO2 huff-n-puff process for enhanced oil recovery in the Bakken Formation. A numerical model was built using the typical reservoir and fracture properties from Middle Bakken to simulate CO2 huff-n-puff process. In this process, we consider CO2 molecular diffusion term to swell oil in matrix since Darcy velocity is negligible due to low permeability. The numerical model was validated with field production data from a horizontal well in Middle Bakken. Based on the history matching results, the relative permeability curves such as water-oil relative permeability and liquid-gas relative permeability, are obtained. Furthermore, the wettability for the Middle Bakken is found to be weak water wet. Simulation results show that the most important parameter is CO2 injection rate, followed by CO2 injection time, number of cycle, CO2 diffusivity. The other parameters such as fracture conductivity, CO2 soaking time, permeability and fracture half-length are less sensitive based on the range investigated in this study. The range for the incremental oil recovery factor at 30 years of production is obtained as 2.5% - 9.4%. This work can provide fundamental understanding of the key parameters controlling the CO2 huff-n-puff process for enhanced oil recovery in the Bakken Formation.

No abstract

Surface diffusion plays a key role in gas mass transfer due to the majority of adsorbed gas with abundant nanopores of organic matter in shale gas reservoirs. Surface diffusion simulation is very complex as a result of high reservoir pressure, surface heterogeneity and non-isothermal desorption in shale gas reservoirs. In this paper, a new model of surface diffusion for adsorbed gas in shale gas reservoirs is established, which is based on a Hwang model derived under low pressure condition and considers the effect of adsorbed gas coverage under high pressure. Additionally, this new model considers the effects of surface heterogeneity, isosteric sorption heat and non-isothermal gas desorption. Results show that: (1) the surface diffusion coefficient increases with pressure and temperature, while it decreases with activation energy and gas molecular weight; (2) contributions of viscous flow, Knudsen diffusion and surface diffusion to the total gas mass transfer are varying during the development of shale gas reservoirs, which are mainly controlled by nanopore-scale and pressure; (3) in micropores (pore radius Ͻ 2nm), the contribution of surface diffusion to the gas mass transfer is dominant, up to 92.95%; in macropores (pore radius Ͼ 50nm), the contribution is less than 4.39%, which is negligible; in mesopores (2nm Ͻ pore radius Ͻ 50nm), the contribution is between micropores and macropores.

A model for gas transport in microfractures of shale and tight gas reservoirs is established. Slip flow and Knudsen diffusion are coupled together to describe general gas transport mechanisms, which include continuous flow, slip flow, transitional flow, and Knudsen diffusion. The ratios of the intermolecular collision frequency and the molecule‐wall collision frequency to the total collision frequency are defined as the weight coefficients of slip flow and Knudsen diffusion, respectively. The model is validated by molecular simulation results. The results show that: (1) the model can reasonably describe the process of the mass transform of different gas transport mechanisms; (2) fracture geometry significantly impacts gas transport. Under the same fracture aperture, the higher the aspect ratio is, the stronger the gas transport capacity, and this phenomenon is more pronounced in the cases with higher gas pressure and larger fracture aperture. © 2015 American Institute of Chemical Engineers AIChE J, 61: 2079–2088, 2015