Recovery Of Shale Gas Research Articles

Acoustic emission monitoring of hydraulic fracturing using carbon dioxide in a small-scale field experiment

Carbon capture and storage (CCS) is a promising method for mitigating the greenhouse effect. If we could utilize carbon dioxide (CO2) for recovery of geothermal energy and shale gas, CCS will be much more eagerly developed and adopted by compensating its cost. We clarified that hydraulic fracturing (HF) using CO2 tended to induce three-dimensionally sinuous cracks with many secondary branches, which appear to be desirable pathways for energy recovery. However, in a laboratory experiment, it was difficult to evaluate crack extension size and effects of macroscopic pre-existing cracks. Thus, we conducted a HF experiment using CO2 in a hole 10 m long that was drilled in a hot rock mass, thus satisfying the temperature necessary to form supercritical (SC) CO2. A bi-wing crack 3.33 m in length was induced along the hole; this crack was significantly larger than the approximately 0.5 m long crack we made with water at another site. The fact that acoustic emission (AE) hypocenters distributed in almost perpendicular to an initial HF crack direction without pressure suggested that CO2 could easily intrude and enhance AE occurrence along a pre-existing crack. Focal mechanisms using P wave first-motion polarities elucidated that many compression-dominant AE events were recorded; these were never observed in similar HF experiment we conducted using water. The compression-dominant events were probably induced by crack closure due to the degassing of injected CO2. Even if CO2 injection induces many AE events, the compressive-dominant events out of them unlikely trigger natural earthquakes because they never create new cracks.

Molecular insights into recovery of shale gas by CO2 injection in kerogen slit nanopores

The unique structures of kerogen greatly complicate the recovery mechanisms of natural gas and challenge the energy industry. In this research, a molecular insight into recovery of shale gas by CO2 in kerogen slit nanostructures are studied using GCGM (Grant Canonical Monte Carlo) and MD (Molecular Dynamics) simulations and compared to that of kerogen matrix. We find that pressure has a positive effect on CH4 and CO2 adsorption capacity, which is opposite to temperature. The isosteric heat of CO2 is larger than CH4, indicating a higher affinity of CO2 to kerogen and lower self-diffusion coefficient. The competitive adsorption of CO2 over CH4 is higher at lower CO2 model fraction, suggesting less amount of CO2 is required to recover the same amount of CH4 at the early stage of CO2 injection. In kerogen slit nanopores, CH4 adsorption state is less stable than in kerogen matrix, which introduces a higher diffusion of CH4. The adsorption selectivities in kerogen matrix are almost over 5, while the selectivities are lower than 3.5 in kerogen slit nanopores. Therefore, the selectivities in kerogen matrix is higher than in slit. It indicates that more CH4 can be displaced out from formation without slits (or fractures) than with fractures when the same amount of CO2 is injected. The displacement efficiency increases with increasing “bulk” pressure, and it can reach over 80% when the “bulk” pressure is 20.0 MPa, suggesting CO2 can be an ideal candidate for CH4 recovery. We also find that a few CH4 are still inside the kerogen matrix, which is difficult to recover by CO2 injection. We hope that our research may serve as a reference for developing shale reservoirs with natural or artificial fractures.

A Production Prediction Method for Shale Gas Wells Based on Multiple Regression

The estimated ultimate recovery (EUR) of a single shale gas well is one of the important evaluation indicators for the scale and benefit development of shale gas, which is affected by many factors such as geological and engineering, so its accurate prediction is difficult. In order to realize the accurate prediction of ultimate recovery, this study considered 172 shale gas wells in the Weiyuan block as samples and selected 19 geological and engineering factors that affect the ultimate recovery of shale gas wells. Furthermore, eight key controlling factors were selected by means of the Pearson correlation coefficient and maximum mutual information coefficient comprehensive evaluation method. The data were divided into training and testing samples. Different numbers of training samples were selected and seven schemes were designed. Based on the key controlling factors, the ultimate recovery prediction model for shale gas wells in this block was established through multiple regression methods. The effectiveness of the prediction model was verified by analyzing the testing samples. The result shows that with the increase of the size of training samples, the error of the ultimate recovery predicted by the model gradually decreases gradually. When predicting the single gas well, the average absolute error of ultimate recovery is less than 20% if the number of the training gas well is more than 80. When analyzing the development potential of similar blocks without drilling, the error of the sum of ultimate recovery is less than 10% if the size of the training gas well reaches 60.

Comparative Study on Mineral-Scale Microcrack Propagation of Shale under Different Loading Methods

Producing a sufficient volume of multiscale crack networks is key to enhancing recovery of shale gas. The formation of crack network largely depends on initiation and propagation of microcracks. To reveal the influence of different loading methods on the propagation of mineral-scale microcracks, this study used the Voronoi tessellation technique to establish a cohesive zone model of shale mineral distribution and applied six different boundary conditions to represent different loading methods. Crack path characteristics, rupture characteristics, continuous crack propagation and turning, and en echelon intermittent crack propagation under different loading methods were compared and analyzed. The essence of different loading methods affecting the length and complexity of cracks was the spreading range of tensile microcracks. The mechanical properties of minerals led to dissimilarities in continuous crack propagation and turning. The formation and propagation of en echelon intermittent fractures of different scales were mainly impacted by the heterogeneity of minerals and mineral aggregates. The spreading direction and connection form of en echelon intermittent fractures were mainly affected by the loading method. Conclusions arising from mineral-scale simulations contribute to understanding the mechanism of microcrack propagation resulting from different loading methods, and these conclusions have a guiding significance to enhanced shale gas recovery.

Hydrocarbon accumulation and key exploration & development technologies of Changning-Weiyuan marine shale gas field, southern Sichuan

China is rich in shale gas resources and has broad prospects for development. However, the quality of shale gas resources in China is different from that in the United States, so independent unique technologies are urgently required in China. In this regard, PetroChina has carried out theoretical and technical researches systematically on shale gas in Longmaxi Formation in southern Sichuan according to its geology-engineering characteristics. Guided by the “three-control” theory for marine shale gas enrichment and high yield (i.e. sedimentary diagenesis controls reservoir, preservation conditions control accumulation, and continuous thickness of Type I reservoir controls production), six key exploration and development technologies in southern China have been innovatively developed for marine shale gas which experienced multi-stage tectonic evolution. The technologies include comprehensive geological evaluation technology, development optimization technology, optimal and fast drilling technology for horizontal well, volume fracturing technology for horizontal well, factory-like operation technology, and efficient clean production technology. These technologies have enabled the large-scale commercial recovery of shale gas. By the end of 2019, PetroChina had obtained proved geological reserves of 1.06 × 1012 m3, had built production capacity of 10 × 109 m3, and had cumulative gas production of 20 × 109 m3 in southern Sichuan. The remarkable results of application are of great significance for vigorously developing shale gas industry to reduce external dependence, ensure national energy security, and realize the strategy of “ecological priority and green development".

The role of supercritical carbon dioxide for recovery of shale gas and sequestration in gas shale reservoirs

This review summarizes the potential and challenges of supercritical carbon dioxide (SC-CO2) enhanced shale gas recovery and sequestration in shale reservoirs.

Interactions of CO2 with Hydrocarbon Liquid Observed from Adsorption of CO2 in Organic-Rich Shale

Whereas the importance of shale oil and gas production to the energy supply is increasing, the recovery of shale oil and gas is low and the environmental performance needs improvement. Injection of...

An optimization model for conductivity of hydraulic fracture networks in the Longmaxi shale, Sichuan basin, Southwest China

Shale gas is an important unconventional resource. The economic recovery of shale gas is only possible when a fracture network with sufficient conductivity is created by hydraulic fracturing, that, if effectively propped, connects fracturing fractures and natural fractures. Focusing on the Longmaxi shale in the Sichuan Basin, Southwest China, we built an optimization model for conductivity of multi-grade fractures based on equivalent seepage theory. We then experimentally analyzed the conductivity of self-propped and sand-propped fractures, and optimized the propping patterns of multi-grade hydraulic fractures in shale gas reservoirs. We concluded that the propping effectiveness of fracture networks could be improved by using low concentrations of small-sized sands and by focusing on creating a large number of self-propped fractures. By applying this understanding to the optimization of fracturing designs for the Longmaxi shale, we successfully created networks of well-propped fractures.

Insights into recovery of multi-component shale gas by CO2 injection: A molecular perspective

Understanding the mechanism behind shale gas recovery is of great importance for achieving optimum shale gas productivity. In this work, we use Grand Canonical Monte Carlo (GCMC) simulations to investigate the adsorption and recovery mechanisms of ternary hydrocarbon mixtures comprising methane, ethane and propane in kerogen nanopores. For the adsorption of hydrocarbon mixtures in kerogen slit pores, density distributions of each component are analyzed and the results indicate that densities of methane and ethane in the first adsorption layer increase as pressure increases, while an opposite trend is observed for propane. A stronger confinement effect is observed on the heavier hydrocarbon components, increasing the difficulty of recovery. For the recovery of the multi-component shale gas, we propose a reference recovery route with pressure drawdown and CO2 injection combined and the recovery efficiency is compared to the condition with only pressure drawdown applied. Significant enhancement in recovery ratio for all three components is observed with the CO2 injection and a better performance is shown on heavier components and smaller pores. An increase of 60% and 40% in propane recovery ratio is achieved in the 2-nm and 4-nm kerogen slit pores, respectively. Recovery mechanisms of pressure drawdown and CO2 injection are investigated in detail. The pressure drawdown method recovers methane from the first adsorption layer and middle of slit pore simultaneously, while extracting ethane and propane mainly from the middle of slit pore; the recovery due to CO2 injection mainly takes place in the adsorption layers. Pressure drawdown tends to extract the lighter components and CO2 injection is efficient in the recovery of heavier hydrocarbons. As pore width increases, the recovery ratio of pressure drawdown increases, while that of CO2 injection decreases. Besides, the CO2 sequestration ratio is higher in smaller kerogen slit pores.

Adsorption induced critical shifts of confined fluids in shale nanopores

Phase equilibrium of shale gas or oil is highly disturbed due to fluid adsorption in densely-developed nanopores. Accurate description of adsorption and its induced critical shifts for confined fluids in nanopores is essential for a better understanding of the underlying mechanisms governing the storage, transport, and recovery of shale gas or oil in shale reservoirs. In this study, first, a novel method for describing fluid adsorption in nanopores was presented on a basis of adsorption thickness (δ) coupled with an initially-proposed parameter (reduced adsorption density β). Second, the two parameters were introduced to modify the molar volume term and then the Peng-Robinson equation of state (PR-EOS) was updated. This proposed model could characterize the quantitative relationship between fluid adsorption and its induced critical shifts. Third, the literature data of critical temperature shift were collected to correlate the reduced adsorption density and dimensionless pore radius. Then, the modified PR-EOS was solved and two generalized analytical formulas were developed for calculating the shifts of critical temperature and pressure caused by fluid adsorption in nanopores. Finally, several key factors including hydrocarbon component and pore size were investigated to demonstrate that the modified PR-EOS showed a satisfactory ability to predict the shifted critical properties of confined fluids.

Effects of Moisture Contents on Shale Gas Recovery and CO2 Sequestration.

Enhanced recovery of shale gas with CO2 injection has attracted extensive attention as it combines the advantages of improved efficiency of shale gas recovery and reduced greenhouse gas emissions via CO2 geological sequestration. On the other hand, the microscopic mechanism of enhanced shale gas recovery with CO2 injection and the influence of the subsurface water confined in the shale nanopores remain ambiguous. Here, we use grand canonical Monte Carlo (GCMC) simulations to investigate the effect of moisture on the shale gas recovery and CO2 sequestration by calculating the adsorption of CH4 and CO2 in dry and moist kerogen slit pores. Simulation results indicate that water accumulates in the form of clusters in the middle of the kerogen slit pore. Formation of water clusters in kerogen slit pores reduces pore filling by methane molecules, resulting in a decrease in the methane sorption capacity. For the sorption of CH4/CO2 binary mixtures in kerogen slit pores, the CH4 sorption capacity decreases as the moisture content increases, whereas the effect of moisture on CO2 sorption capacity is related to its mole fraction in the CH4/CO2 binary mixture. Furthermore, we propose a reference route for shale gas recovery and find that the pressure drawdown and CO2 injection exhibit different mechanisms for gas recovery. Pressure drawdown mainly extracts the CH4 molecules distributed in the middle of kerogen slit pores, while CO2 injection recovers CH4 molecules from the adsorption layer. When the water content increases, the recovery ratio of the pressure drawdown declines, while that of CO2 injection increases, especially in the first stage of CO2 injection. The CO2 sequestration efficiency is higher under higher water content. These findings provide the theoretical foundation for optimization of the shale gas recovery process, as well as effective CO2 sequestration in depleted gas reservoirs.

Controls of CO2–N2 gas flood ratios on enhanced shale gas recovery and ultimate CO2 sequestration

Primary production of less than 25% of original gas in place (OGIP) may be elevated by enhanced shale gas recovery (ESGR) using either pure CO2 or N2 as injected stimulants. Alternatively, injecting mixtures of CO2 and N2 may potentially optimize recovery of natural gas and beneficially sequester CO2. We develop a dual-porosity, dual-permeability finite element (FEM) model coupled with multi-component gas flow and sorption behavior to 1) explore the evolution of sorption-induced strain resulting from competitive adsorption and its influence on the matrix and fracture permeability; 2) define cumulative production of CH4 and 3) evaluate the amount of CO2 sequestered in the reservoir; Results show that pure-CO2 injection can increase shale gas recovery by ∼20%. Conversely, pure-N2 injection can increase shale gas recovery by ∼80%. Injecting mixtures of CO2 and N2 can increase shale gas recovery between these end-member magnitudes of ∼20%–∼80% depending on the gas composition. We show that a higher proportion of CO2 in the injected CO2–N2 mixture will result in the decreased recovery of shale gas. However, at the same injection pressure, injecting CO2–N2 mixtures with a higher proportion of CO2 does not always result in more CO2 sequestered in the reservoir. Indeed, when the CO2 injection ratio is >70%, as explored in this study, increasing the CO2 injection ratio will result in less CO2 sequestered. This is because, as the CO2–N2 gas ratio increases, shale gas recovery decreases and results in more CH4 left in the reservoir to compete with CO2 for sorption sites and finally resulting in less CO2 sequestered.

The numerical simulation of thermal recovery considering rock deformation in shale gas reservoir

Recently, shale gas is a hot spot of research as an unconventional resource. Advances in horizontal well drilling technology and fracturing technology have contributed to increased shale gas recovery. Different from conventional gas reservoirs, the adsorption gas content is as high as 85%, so the amount of adsorbed gas liberated from the matrix surface is very helpful for ultimately improving the recovery of shale gas. Recently, some progress has been made in the process of hydraulic fracture heating technology. The event that temperature variation promotes the release of adsorbed gas and thus enhances oil recovery has not been fully studied. In addition, during shale gas production, stress sensitivity, adsorption desorption and temperature will all have a significant effect on rock deformation, which will change the permeability of the matrix and fractures.To study the effect of thermal recovery based on coupled geomechanical effects and fluid flow. A numerical model of shale gas thermal recovery considering Knudsen diffusion, adsorption desorption and stress sensitivity was established to reflect the production process of shale gas. Moreover, discrete fracture is employed to describe hydraulic fractures and natural fractures. The influence of thermal expansion on rock deformation is considered in the geomechanical effect, and the permeability formula suitable for shale gas thermal recovery is developed. Finally, the effects of different parameters on thermal recovery were studied separately.It is obvious that heating hydraulic fractures improves the recovery of shale gas by promoting the liberate of adsorbed gas. A large amount of adsorbed gas is produced as the stimulation temperature increases. Considering the stress-sensitive permeability can more accurately reflect the change of permeability in the shale gas thermal recovery process, so as to more accurately predict the production of shale gas. The increase in recovery rate of shale gas thermal recovery depends on the stimulation temperature, bottom hole pressure, matrix heat capacity, thermal conductivity, Langmuir volume and matrix permeability. The larger the Langmuir volume and the higher the bottom hole pressure, the better the thermal recovery effect for improving shale gas recovery.

The impacts of human activity on the microorganisms in deep subsurface

In the deep biosphere, there are a large number of microorganisms that are mainly bacteria and archaea. Fungi and viruses are also found in deep subsurface. These microorganisms found in the deep biosphere are functionally and phylogenetically diverse. Different from the microorganisms on the Earth surface where they use sunlight as their primary energy source, the microorganisms in deep subsurface employ the hydrogen gas and methane, which are produced mainly from geochemical interactions between water and rock, as their primary energy and/or electron sources. Human activities impact substantially on the deep subsurface environment as well as the microorganisms living there. This review focuses on the impacts of recovery of shale gas by horizontal drilling and hydraulic fracturing (or fracking), geological storage of nuclear wastes and CO2 capture and geological storage on the microorganisms in the deep biosphere. Shale gas is the natural gas locked within the black shale in deep subsurface. Horizontal drilling and fracking are widely used to recover the shale gas. Research results demonstrate that the structures and functions of microbial community differ greatly at different stages of recovery of shale gas by fracking. Results also find that viruses play crucial roles in influencing the structures and functions of microbial community during different stages of recovery of shale gas by fracking. Among the microorganisms identified, the methanogens in the black shale impact positively on the natural gas recovery by producing methane. In contrast to the methanogens, the acid-producing microorganisms impact negatively on the natural gas recovery by causing reservoir souring and corrosion of metal structures. Thus, the microorganisms in the deep subsurface play dual roles in impacting the natural gas recovery. Nuclear wastes are the materials containing or contaminated with radionuclide. Safe storage of nuclear wastes is the most important factor that determines whether nuclear industry and peaceful use of nuclear energy can be continuously developed. Currently, geological storage in deep subsurface is the only acceptable way for long-term and safe storage of the nuclear wastes whose half-life is long and radioactivity is high. For this reason, underground research laboratories (URL) are constructed to assess potential impacts of the microorganisms in the deep subsurface on the safe storage of nuclear wastes in the geological formation. The results demonstrate that complex of microbial communities reside in the geological formations planned for storage of nuclear wastes. Although structures and functions of these microbial communities vary, the sulfate-reducing bacteria found in these communities may corrode the metal structures, while gas-producing microorganisms may increase the chamber pressure of the storage structure. All of these microbial activities may damage the structure and function of the nuclear waste geological repository. In contrast, the Fe(III)-reducing microorganisms may stabilize nuclear wastes in the repository. CO2 capture and storage could slow down the global warming by reducing CO2 emissions. Research results show that certain group of bacteria live under supercritical CO2 condition in the deep subsurface. Moreover, geological storage of supercritical CO2 acidify the water in deep subsurface, which increases dissolution of rocks and minerals. Consequently, it changes the chemical environment and the structures and functions of microbial community in the deep subsurface. In turn, the responses of microbial communities to the addition of supercritical CO2 may affect the stability of CO2 storage in the geological settings. Over the past decades, our understanding of the impacts of human activity on the microorganisms in deep subsurface has been advanced significantly. A common theme emerging from the results of these studies is that the microorganisms influenced by human activity may have either positive or negative effects in recovery of shale gas and geological storage of nuclear waste and CO2.

Incorporation of sustainability in process control of hydraulic fracturing in unconventional reservoirs

Typically, the term shale oil refers to natural oil trapped in rock of low porosity and ultra-low permeability. What has made the recovery of shale oil and gas economically viable is the extensive use of hydraulic fracturing and horizontal drilling. Research on the relationship between the distribution of propping agent, called proppant, and shale well performance indicates that uniformity of proppant bank height and suspended proppant concentration across the fracture at the end of pumping determines the productivity of produced wells. However, it is important to note that traditional fracturing fluid pumping schedules have not considered the environmental and economic impacts of the post-fracturing process such as treatment and reuse of flowback water from fractured wells. Motivated by this consideration, a control framework is proposed to integrate sustainability considerations of the post-fracturing process into the hydraulic fracturing process. In this regard, a dynamic model is developed to describe the flow rate and the concentration of total dissolved solids (TDS) in flowback water from fractured wells. Thermal membrane distillation is considered for the removal of TDS. An optimization problem is formulated to find the optimal process that consists of hydraulic fracturing, storage, transportation, and water treatment, through minimizing annualized cost and water footprint of the process. The capabilities of the proposed approach are illustrated through the simulation results of different scenarios that are performed to examine effects of water availability on the productivity of stimulated wells. Finally, the environmental impact of flowback water treatment is evaluated using TRACI, a tool for the reduction and assessment of chemical and other environmental impacts.

Microstructure and adsorption properties of organic matter in Chinese Cambrian gas shale: Experimental characterization, molecular modeling and molecular simulation

A representative molecular model of shale organic matter (OM) is prerequisite to further theoretic investigation on the fundamental mechanisms governing storage, transport and recovery of shale gas. In this work, a systematic strategy to prepare structural and compositional properties of OM is reported first, and then a realistic molecular model of Chinese Cambrian OM is generated based on analytical experimental data. Microstructure characterization and adsorption simulation are further performed using molecular dynamics simulation and grand canonical Monte Carlo simulations, respectively. The OM model, composed of kerogen macromolecules, bitumen components and residual lighter components, shows a reasonable representation of realistic Cambrian OM with respect to structural parameters, generic compositions, physical density and porosity. The OM porous network consists of dominant ultra-micropores and limited micropores. Compared with heavier components, lighter components are more inclined to occupy accessible pores. Interestingly, lighter components are observed to appear in pairs due to competitive adsorption around heteroatom groups. Water molecules are scattered in the system because of abundant functional groups and poor pore connectivity. The OM skeleton represents the adsorption behaviors of methane, carbon dioxide and nitrogen well. The adsorption capacity is carbon dioxide > methane > nitrogen. A higher adsorption capacity corresponds to a lower pressure when the excess isotherm reaches the maximum. The adsorption behaviors of heavier hydrocarbon species (ethane, propane and n-butane) cannot be represented in the OM skeleton with ultra-micropores and limited micropores, and the effect of molecular sizes of these species cannot be neglected. This work reports a systematic construction process for realistic molecular model of shale OM, and the representative OM model can serve as a starting point to explore gas adsorption and transport mechanism in shale organic pores at microscopic scale.

Pore structure, wettability, and spontaneous imbibition of Woodford Shale, Permian Basin, West Texas

Even after more than 30 years of exploration and production, low total recovery of shale gas (<30%) and tight oil (5%–10%) constrains sustainable shale hydrocarbon development in the United States. Since the Woodford Shale is one of the principal source rocks of the Permian Basin, West Texas, this study uses core samples of Woodford Shale from the Reliance Triple Crown (RTC) #1 well in Pecos County, Texas, to examine mineralogy, pore structure, wetting characteristics, imbibition behavior, and edge-accessible porosity with the following complementary tests: X-ray diffraction (XRD), mercury injection capillary pressure (MICP), contact angle measurement of various fluids, fluid imbibition into initially-dry shale, and edge-accessible pore connectivity from vacuum saturation-high pressure impregnation with tracers-containing n-decane. The wettability and imbibition tests use both polar (hydrophilic, deionized water) and nonpolar (hydrophobic, n-decane) fluids. Our results indicate that Woodford Shale samples (Upper, Middle, and Lower Members) have different geologic (mineralogy) and reservoir (e.g., total organic carbon, porosity, and permeability) characteristics. MICP analyses show that the median pore-throat diameters for the Woodford Shale are 3.7–5.4 nm, and almost 70–80% of pore-throats by volume are smaller than 100 nm, with high tortuosity for fluid flow and mass movement. Spontaneous fluid imbibition into Woodford Shale exhibits imbibition slopes (from the plots of log imbibition vs. log time) close to ¼ for deionized water and ½ for n-decane, consistent with contact angle measurements that indicate a marginally water-wet, but very strong oil-wet, nature for these shales. Edge-accessible pore connectivity tests indicate that well-connected hydrophobic pore networks (primarily organic matter-hosted pores) have pore-throat sizes of approximately 5 nm and experience molecular entanglement with nm-sized tracers used in vacuum saturation tests. Our analyses suggest that the middle Woodford member will be the best interval for stimulation and hydrocarbon production. The findings from these complementary experimental approaches suggest low connectivity of tortuous nanopore networks and mixed-wet characteristics, which could have implications for total hydrocarbon recovery in Woodford Shale.

Determination of the absolute adsorption/desorption isotherms of CH4 and n-C4H10 on shale from a nano-scale perspective

Accurate description of absolute adsorption/desorption behavior for hydrocarbons on shale is of critical importance to the understanding of the fundamental mechanisms governing the storage, transport, and recovery of shale gas or shale gas condensate in shale reservoirs. By applying a thermogravimetric method, we first measure the excess adsorption/desorption isotherms of pure CH4 and n-C4H10 on shale samples over the temperature range of 303.15–393.15 K. The maximum test pressures considered for CH4 and n-C4H10 are 50 bar and 2 bar, respectively. Grand Canonical Monte Carlo (GCMC) simulations are then applied to calculate the density of the adsorption phase by considering the fluid-pore surface interactions. We use such calculated density of the adsorption phase to calibrate the excess adsorption/desorption isotherms, which enables us to eventually obtain the absolute adsorption/desorption isotherms. Such approach for estimating the density of the adsorption phase is essentially different from the commonly used approaches in which the density of the adsorption phase is considered to be independent of temperature, pressure, and pore size.The adsorption/desorption test results show that both CH4 and n-C4H10 exhibit more adsorption as temperature decreases or pressure increases. Their adsorption/desorption isotherms exhibit hysteresis phenomenon and this phenomenon weakens as temperature increases. Comparatively, the hysteresis behavior observed for n-C4H10 is more obvious than that for CH4. Compared with CH4, n-C4H10 has higher adsorption capacity under the same condition, indicating its higher affinity towards the shale with organic matters. As for the conventional approaches, the density calculated from the van der Waals constant b or the liquid hydrocarbon density can be used to reasonably well evaluate the absolute adsorption isotherms of n-C4H10 on shale, but tends to underestimate the absolute adsorption of CH4 on shale. GCMC simulations show that the density of the adsorption phase is strongly correlated with system pressure, temperature, and pore size. Compared to the conventional approaches, GCMC simulations can better capture the in-situ density of adsorption phase; on the basis of the in-situ density of adsorption phase, we can then achieve more accurate determination of the absolute adsorption isotherms of a given hydrocarbon on shale. This study raises the imperativeness of leveraging more sophisticated simulation tools (such as GCMC) for more accurate determination of absolute adsorption isotherms.

Shale gas development: Opportunities and challenges for rock mechanics

Multistage hydraulic stimulations on long-lateral horizontal wells are critical technologies for improving shale gas production in China. With deeper exploration and development in depth, however, more challenges spring up. For example, high risks in drilling and completion, low-efficient stimulation, and rapid production decline, etc. The topics are related with failure and seepage modeling in shale gas reservoirs, for which the nature of the problems is highly focused on rock mechanics. More breakthroughs are excepted in laboratory tests, fracture networks characterization and seepage modeling, multi-field coupling and poroelasticity theories. Although China has achieved initial victory in shale gas development, more challenges remains to be disposed by deepening theories of rock mechanics and industrial innovations. Meanwhile, clean and cost-effective recovery of shale gas is the key role throughout the life-cycle of development. In this paper, we review geomechanics assessments, fracture mechanics, seepage and fluid-solid coupling theories used in shale gas reservoirs. We cover the topics of laboratory tests, wellbore safety and effective development technologies, with discussing the research direction and hotspot in the future.

Recovery of Multicomponent Shale Gas from Single Nanopores

The adsorption of multicomponent gas mixtures in shale formations and their recovery are of great interest to the shale gas industry. Here we report molecular dynamics simulations of the adsorption of methane/ethane mixtures in 2 and 4 nm-wide nanopores and their recovery from these nanopores. Surface adsorption contributes significantly to the storage of methane and ethane inside the pores, and ethane is enriched inside the nanopores in equilibrium with bulk methane–ethane mixtures. The enrichment of ethane is enhanced as the pore is narrowed but is weakened as the pressure increases due to entropic effects. These effects are captured by the ideal adsorbed solution (IAS) theory, but the theory overestimates the adsorption of both gases. Upon opening the mouth of the nanopores to gas baths with lower pressure, both gases enter the bath. The production rates of both gases show only weak deviation from the square root scaling law before the gas diffusion front reaches the dead end of the pores. The ratio of...