scholarly journals Numerical Simulation of Gas Production from Gas Shale Reservoirs—Influence of Gas Sorption Hysteresis

Energies ◽  
2019 ◽  
Vol 12 (18) ◽  
pp. 3405 ◽  
Author(s):  
Jamiu M. Ekundayo ◽  
Reza Rezaee
Keyword(s):  
Adsorption Isotherms ◽  
Shale Gas ◽  
Computer Modelling ◽  
Three Dimensional ◽  
Gas Production ◽  
Gas Sorption ◽  
Gas Desorption ◽  
Dual Porosity Model ◽  
Desorption Isotherms ◽  
Shale Reservoirs

The true contribution of gas desorption to shale gas production is often overshadowed by the use of adsorption isotherms for desorbed gas calculations on the assumption that both processes are identical under high pressure, high temperature conditions. In this study, three shale samples were used to study the adsorption and desorption isotherms of methane at a temperature of 80 °C, using volumetric method. The resulting isotherms were modeled using the Langmuir model, following the conversion of measured excess amounts to absolute values. All three samples exhibited significant hysteresis between the sorption processes and the desorption isotherms gave lower Langmuir parameters than the corresponding adsorption isotherms. Langmuir volume showed positive correlation with total organic carbon (TOC) content for both sorption processes. A compositional three-dimensional (3D), dual-porosity model was then developed in GEM® (a product of the Computer Modelling Group (CMG) Ltd., Calgary, AB, Canada) to test the effect of the observed hysteresis on shale gas production. For each sample, a base scenario, corresponding to a “no-sorption” case was compared against two other cases; one with adsorption Langmuir parameters (adsorption case) and the other with desorption Langmuir parameters (desorption case). The simulation results showed that while gas production can be significantly under-predicted if gas sorption is not considered, the use of adsorption isotherms in lieu of desorption can lead to over-prediction of gas production performances.

scholarly journals Molecular Investigation on the Displacement Characteristics of CH4 by CO2, N2 and Their Mixture in a Composite Shale Model

Energies ◽  
2020 ◽  
Vol 14 (1) ◽  
pp. 2
Author(s):  
Liang Gong ◽  
Yuan Zhang ◽  
Na Li ◽  
Ze-Kai Gu ◽  
Bin Ding ◽  
...  
Keyword(s):  
Energy Consumption ◽  
Shale Gas ◽  
Injection Pressure ◽  
Gas Production ◽  
Formation Temperature ◽  
Displacement Efficiency ◽  
Gas Recovery ◽  
Displacement Capacity ◽  
Molecular Investigation ◽  
Shale Reservoirs

The rapid growth in energy consumption and environmental pollution have greatly stimulated the exploration and utilization of shale gas. The injection of gases such as CO2, N2, and their mixture is currently regarded as one of the most effective ways to enhance gas recovery from shale reservoirs. In this study, molecular simulations were conducted on a kaolinite–kerogen IID composite shale matrix to explore the displacement characteristics of CH4 using different injection gases, including CO2, N2, and their mixture. The results show that when the injection pressure was lower than 10 MPa, increasing the injection pressure improved the displacement capacity of CH4 by CO2. Correspondingly, an increase of formation temperature also increased the displacement efficiency of CH4, but an increase of pore size slightly increased this displacement efficiency. Moreover, it was found that when the proportion of CO2 and N2 was 1:1, the displacement efficiency of CH4 was the highest, which proved that the simultaneous injection of CO2 and N2 had a synergistic effect on shale gas production. The results of this paper will provide guidance and reference for the displacement exploitation of shale gas by injection gases.

Numerical Simulation of Shale Gas Production

2011 ◽  
Vol 402 ◽  
pp. 804-807 ◽  
Author(s):  
Song Ru Mu ◽  
Shi Cheng Zhang
Keyword(s):  
Shale Gas ◽  
Simulation Models ◽  
Fracture Network ◽  
Gas Production ◽  
Wire Mesh ◽  
Well Performance ◽  
Gas Reservoirs ◽  
Shale Gas Reservoirs ◽  
Shale Reservoirs ◽  
Fracture Mapping

Shale gas reservoirs require a large fracture network to maximize well performance. Microseismic fracture mapping has shown that large fracture networks can be generated in many shale reservoirs. The application of microseismic fracture mapping measurements requires estimation of the structure of the complex hydraulic fracture or the volume of the reservoir that has been stimulated by the fracture treatment. There are three primary approaches used to incorporate microseismic measurements into reservoir simulation models: discrete modeling of the complex fracture network, wire-mesh model, and dual porosity model. This paper discuss the different simulation model, the results provided insights into effective stimulation designs and flow mechanism for shale gas reservoirs.

Acadian hinterland-vergent detachment structures in the southwestern Appalachian Plateau: Implications for the Marcellus Shale gas exploration and production

2018 ◽  
Vol 6 (4) ◽  
pp. SN85-SN99 ◽  
Author(s):  
Dengliang Gao ◽  
Thomas Donahoe ◽  
Taizhong Duan ◽  
Peter Sullivan
Keyword(s):  
Shale Gas ◽  
Middle Devonian ◽  
Marcellus Shale ◽  
Three Dimensional ◽  
Gas Production ◽  
Seismic Facies ◽  
Seismic Structure ◽  
Appalachian Plateau ◽  
Structural Style ◽  
Exploration And Production

Three-dimensional seismic data in southwestern Pennsylvania in the Appalachian Plateau demonstrate that the structural style in the Devonian section is dominated by east-vergent folds and reverse faults, which contrasts with that in the Valley and Ridge Province where west-vergent folds and thrusts dominate. Vertical (cross-stratal) variations in fold curvature and fault throw indicate that the intensity of shortening increases from the Salina (Upper Silurian) to the Onondaga (Middle Devonian) and then decreases from the Onondaga to the Elk (Upper Devonian). Lateral (along-stratal) variations in fold curvature and fault throw indicate that the folds and faults tend to propagate in the cross-strike and along-strike directions. Isochron thickness below the Onondaga increases on the anticlinal, up-thrown side of the faults, whereas isochron thickness above the Onondaga increases to the synclinal, down-thrown side of the faults. In concert with seismic structure and isochron thickness, seismic facies see vertical and lateral variations that are spatially and temporally related to folds and faults. Four years of gas production data from the Middle Devonian Marcellus Shale show that the gas productivity drops near the regional reverse faults, whereas regional drilling patterns from a broader perspective of the Plateau reveal operational gaps near major cross-regional wrench faults. These observations are indicative of the dynamic interplay among hinterland-vergent detachment deformation, syntectonic sedimentation, and shale gas preservation during the Acadian (Middle Devonian–Early Mississippian).

scholarly journals Multi-Size Proppant Pumping Schedule of Hydraulic Fracturing: Application to a MP-PIC Model of Unconventional Reservoir for Enhanced Gas Production

Processes ◽  
2020 ◽  
Vol 8 (5) ◽  
pp. 570 ◽  
Author(s):  
Prashanth Siddhamshetty ◽  
Shaowen Mao ◽  
Kan Wu ◽  
Joseph Sang-Il Kwon
Keyword(s):  
Hydraulic Fracturing ◽  
Shale Gas ◽  
Computational Cost ◽  
Three Dimensional ◽  
Sensitivity Study ◽  
Gas Production ◽  
Field Scale ◽  
Fracture Geometry ◽  
Fracture Conductivity ◽  
Proppant Transport

Slickwater hydraulic fracturing is becoming a prevalent approach to economically recovering shale hydrocarbon. It is very important to understand the proppant’s transport behavior during slickwater hydraulic fracturing treatment for effective creation of a desired propped fracture geometry. The currently available models are either oversimplified or have been performed at limited length scales to avoid high computational requirements. Another limitation is that the currently available hydraulic fracturing simulators are developed using only single-sized proppant particles. Motivated by this, in this work, a computationally efficient, three-dimensional, multiphase particle-in-cell (MP-PIC) model was employed to simulate the multi-size proppant transport in a field-scale geometry using the Eulerian–Lagrangian framework. Instead of tracking each particle, groups of particles (called parcels) are tracked, which allows one to simulate the proppant transport in field-scale geometries at an affordable computational cost. Then, we found from our sensitivity study that pumping schedules significantly affect propped fracture surface area and average fracture conductivity, thereby influencing shale gas production. Motivated by these results, we propose an optimization framework using the MP-PIC model to design the multi-size proppant pumping schedule that maximizes shale gas production from unconventional reservoirs for given fracturing resources.

scholarly journals Effect of reservoir pressure and total organic content on adsorbed gas production in shale reservoirs: a numerical modelling study

2022 ◽  
Vol 15 (2) ◽  
Author(s):  
Moataz Mansi ◽  
Mohamed Almobarak ◽  
Christopher Lagat ◽  
Quan Xie
Keyword(s):  
Numerical Modelling ◽  
Shale Gas ◽  
Organic Content ◽  
Gas Production ◽  
Reservoir Pressure ◽  
Adsorbed Gas ◽  
Total Organic Content ◽  
Simulation Results ◽  
Shale Reservoirs ◽  
The Impact

AbstractAdsorbed gas plays a key role in organic-rich shale gas production due to its potential to contribute up to 60% of the total gas production. The amount of gas potentially adsorbed on organic-rich shale is controlled by thermal maturity, total organic content (TOC), and reservoir pressure. Whilst those factors have been extensively studied in literature, the factors governing desorption behaviour have not been elucidated, presenting a substantial impediment in managing and predicting the performance of shale gas reservoirs. Therefore, in this paper, a simulation study was carried out to examine the effect of reservoir depth and TOC on the contribution of adsorbed gas to shale gas production. The multi-porosity and multi-permeability model, hydraulic fractures, and local grid refinements were incorporated in the numerical modelling to simulate gas storage and transient behaviour within matrix and fracture regions. The model was then calibrated using core data analysis from literature for Barnett shales. Sensitivity analysis was performed on a range of reservoir depth and TOC to quantify and investigate the contribution of adsorbed gas to total gas production. The simulation results show the contribution of adsorbed gas to shale gas production decreases with increasing reservoir depth regardless of TOC. In contrast, the contribution increases with increasing TOC. However, the impact of TOC on the contribution of adsorbed gas production becomes minor with increasing reservoir depth (pressure). Moreover, the results suggest that adsorbed gas may contribute up to 26% of the total gas production in shallow (below 4,000 feet) shale plays. These study findings highlight the importance of Langmuir isothermal behaviour in shallow shale plays and enhance understanding of desorption behaviour in shale reservoirs; they offer significant contributions to reaching the target of net-zero CO2 emissions for energy transitions by exhibiting insights in the application of enhanced shale gas recovery and CO2 sequestration — in particular, the simulation results suggest that CO2 injection into shallow shale reservoirs rich in TOC, would give a much better performance to unlock the adsorbed gas and sequestrate CO2 compared to deep shales.

scholarly journals Types and Quantitative Characterization of Microfractures in the Continental Shale of the Da’anzhai Member of the Ziliujing Formation in Northeast Sichuan, China

Minerals ◽  
2021 ◽  
Vol 11 (8) ◽  
pp. 870
Author(s):  
Zhujiang Liu ◽  
Hengyuan Qiu ◽  
Zhenxue Jiang ◽  
Ruobing Liu ◽  
Xiangfeng Wei ◽  
...  
Keyword(s):  
Organic Matter ◽  
Shale Gas ◽  
Gas Flow ◽  
Pore Space ◽  
Three Dimensional ◽  
Total Pore Volume ◽  
Ct Scanning ◽  
Nitrogen Adsorption ◽  
Tectonic Stress ◽  
Shale Reservoirs

A number of wells in the Sichuan Basin of China have tested industrial gas flow pressure arising from the shale of the Da’anzhai section of the Ziliujing Formation, revealing good exploration potential. Microfractures in shales affect the enrichment and preservation of shale gas and are important storage spaces and seepage channels for gas. In order to increase productivity and to reduce the risks associated with shale gas exploration, the types, connectivity, and proportion of microfractures in the Da’anzhai Member have been studied in this work by core and thin section observations, micro-CT, scanning electron microscopy, nitrogen adsorption, and high-pressure mercury intrusion. The results show that four types of fractures have developed in the shale of the Da’anzhai section: microfractures caused by tectonic stress, diagenetic shrinkage fractures of clay minerals, marginal shrinkage fractures of organic matter, and microfractures inside mineral particles. Among these, structural fractures and organic matter contraction fractures are the main types and are significant for shale reservoirs and seepage. The structural microfractures are mainly opened and are well-developed in the shale, with a straight shape, mainly between bedding, with the fracture surface being curved, fully opened, and mainly tensile. Organic matter fractures often develop on the edge of the contact between organic matter and minerals, presenting a slit-like appearance. The fractures related to bedding in the shale are particularly developed, with larger openings, wider extensions, intersecting and expanding, and forming a three-dimensional interconnected pore-fracture system. Based on image recognition, generally speaking, microfractures account for about 20% of the total pore volume. However, the degree of the microfractures’ development varies greatly, depending upon the structural environment, with the proportion of microfractures in fault-wrinkle belts and high-steep zones reaching 40% to 90% of the total pore space. On the other hand, micro-fractures in areas with underdeveloped structures account for about 10% of the total pore space.

scholarly journals Experimental Study on the Characteristics of Adsorbed Gas and Gas Production in Shale Formations

Geofluids ◽  
2021 ◽  
Vol 2021 ◽  
pp. 1-12
Author(s):  
Zhiming Hu ◽  
Xianggang Duan ◽  
Nan Shao ◽  
Yingying Xu ◽  
Jin Chang ◽  
...  
Keyword(s):  
Shale Gas ◽  
Physical Simulation ◽  
Gas Production ◽  
Production Optimization ◽  
Gas Reservoirs ◽  
Tight Sandstone ◽  
Free Gas ◽  
Adsorbed Gas ◽  
Shale Gas Reservoirs ◽  
Shale Reservoirs

Adsorbed gas and free gas both exist in shale reservoirs simultaneously due to the unique nanoscale pore structure, resulting in the complex flow mechanism of gas in the reservoir during the development process. The dynamic performance analysis of shale reservoirs has mostly been conducted by the numerical simulation and theoretical model, while the physical simulation method for relevant research is seen rarely in the literature. Thus, in this paper, an experiment system was designed to simulate the degraded development experiments of shale, coal, and tight sandstone to reveal the output law of gas in different occurrence states of shale reservoirs and clarify the pressure propagation rules of different reservoirs, and then, adsorption gas and free gas production laws were studied by theoretical models. Research indicated the following: (1) The gas occurrence state is the main factor that causes the difference of the pressure drop rate and gas production law of shale, coal, and tight sandstone. During the early stage of the development of shale gas, the free gas is mainly produced; the final contribution of free gas production can reach more than 90%. (2) The static desorption and dynamic experiments confirm that the critical desorption pressure of adsorbed gas is generally between 12 and 15 MPa. When the gas reservoir pressure is lower than the critical desorption pressure in shale and coal formation, desorption occurs. Due to the slow propagation of shale matrix pressure, desorption of adsorbed gas occurs mainly in the low-pressure region close to the fracture surface. (3) The material balance theory of closed gas reservoirs and the one-dimensional flow model of shale gas have subsequently validated the production performance law of adsorbed gas and free gas by the physical simulation. Therefore, in the practical development of shale gas reservoirs, it is recommended to shorten the matrix supply distance, reduce the pressure in the fracture, increase the effective pressure gradient, and enhance the potential utilization of adsorbed gas as soon as possible to increase the ultimate recovery. The findings of this study can help for a better understanding of the shale reservoir utilization law so as to provide a reference for production optimization and development plan formulation of the shale gas reservoirs.

Sign in / Sign up

Export Citation Format

Share Document