Depleted Shale Gas Reservoirs Research Articles

Electric Field Control of CO2 Distribution in Kerogen Slit of Depleted Shale Gas Reservoirs: Implications for CO2 Sequestration

Electric Field Control of CO₂ Distribution in Kerogen Slit of Depleted Shale Gas Reservoirs: Implications for CO₂ Sequestration

Molecular simulation to understand the effect of methane concentration and moisture contents on hydrogen adsorption in kerogens

The adsorption behaviors of methane(CH4), hydrogen(H2), and their mixtures are crucial for estimating the underground hydrogen storage(UHS) capacity in depleted shale gas reservoirs. In this study, we developed four formulated kerogen models, each representing different maturation levels of type II kerogen molecules via utilizing molecular dynamics (MD) methodologies. We investigated the adsorption characteristics of pure H2 and mixed gases(H2 and CH4) on these kerogen models with varying gas components(0.5:0.5 to 0.9:0.1) and moisture content(0–3.0 wt percentage) through grand canonical Monte Carlo(GCMC) simulations. Our findings reveal that pure H2 lacks a pressure point for adsorption equilibrium below 100 MPa at ambient temperature(298K). The competitive adsorption dynamics between H2 and CH4 on kerogen models demonstrate that CH4 exhibits stronger selectivity at lower pressures. Yet, this selectivity diminishes compared to H2 as system pressure increases, indicating turning points in pressure buildup with kerogen maturity. Additionally, the presence of pre-loading H2O molecules reduces the adsorption capacity of mixed gases, particularly affecting CH4 more than H2. This study offers profound insights into the effect of kerogen maturity and moisture content on the interaction between H2/CH4 and kerogen at a microscopic scale.

Hydrogen Geostorage in Organic-Rich Shales: Critical Insights Into the Role of Cushion Gas in Hydrogen Accumulation within Organic Nanoporous Systems

Summary Depleted shale formations have the potential for hydrogen geostorage. The storage mechanisms, however, are complex and influenced by several factors including mineralogy, pore size distribution, residual hydrocarbons in place, and the choice of cushion gas. This study aims to investigate hydrogen distribution within this multiscale pore system, with a focus on understanding how hydrogen accumulates in the organic nanoporous network. Such insights are critical for the long-term storage and recovery assessments. Using molecular simulations, representative organic matter comprising nanoporous kerogen and nanopores of different sizes was constructed. Hydrogen intake of the organic system in the presence of residual amount of natural gas was quantified, considering multiple hydrogen injection scenarios. Despite stronger chemical affinity toward natural gas, hydrogen accumulated in all pore sizes, even the smallest, potentially beneficial for long-term storage but hindering rapid recovery. Moreover, the study was extended to investigate the role of cushion gas in the accumulation of hydrogen in organic structures. It was found that introducing cushion gases, such as methane and carbon dioxide, reduces hydrogen intake in the nanopores, with carbon dioxide being the most effective due to its stronger attraction to kerogen. Nitrogen, on the other hand, had relatively lower impact. The results were consistent with the observed trends in the analysis of the nonbonding energy of all systems. The results reported in this study provide critical insights into the factors influencing hydrogen accumulation in the organic constituents of shale formations for an optimized design of hydrogen geostorage in depleted shale gas reservoirs.

Hydrogen-water-rock interaction from the perspective of underground hydrogen storage: Micromechanical properties and mineral content of rock

Underground hydrogen storage (UHS) in depleted oil and gas reservoirs is recognized as the most promising large-scale hydrogen storage method. The hydrogen-water-rock interaction during the long-term storage of hydrogen is an important factor affecting the long-term stability of the formation and evaluating the effect of hydrogen storage. This study focuses on the influence of hydrogen-water-rock interaction on the micromechanical properties and mineral content of different rocks in the process of UHS, compares the differences in the influence of gas medium and water content characteristics on rock properties, and then evaluates the best hydrogen storage conditions. Hydrogen-water-rock interaction can significantly improve the microscopic mechanical properties of rocks and enhance the stability of reservoirs and cap rocks, which is beneficial for long-term hydrogen storage. H2O and H+ are important media for the reaction of H2 with rocks, which can promote the reaction and dissolution of some silicate minerals (such as clay and feldspar) and carbonate minerals. However, H2O and CH4 are more likely to be adsorbed on the surface of hydrophilic inorganic minerals to form water film and gas film, hindering the direct contact of H2 with minerals, which reduces the reaction intensity of hydrogen with rocks, indicating a decrease in hydrogen loss. Compared with sandstone, shale contains a large amount of organic matter and clay. H2 and CH4 will preferentially be adsorbed on the surface of the pores of these substances, reducing the content of hydrogen that contacts and reacts with inorganic minerals, so the reaction intensity of shale is generally weaker than that of sandstone. Considering the influence of hydrogen-water-rock interaction on rock properties and hydrogen loss during long-term hydrogen storage, depleted shale gas reservoirs with less water content and cushion gas such as CH4 may be a better large-scale UHS method than conventional depleted gas reservoirs. This work helps to screen the optimal hydrogen storage conditions and provides a reference for the site selection and construction of UHS in depleted oil and gas reservoirs.

Molecular Simulation of Competitive Adsorption of Hydrogen and Methane: Analysis of Hydrogen Storage Feasibility in Depleted Shale Gas Reservoirs

Summary As a clean energy carrier, hydrogen (H2) is considered an indispensable part of the energy transition roadmap. To meet increasing energy demand, extremely large storage capacities are required. Previous studies have focused on underground H2 storage in conventional depleted gas reservoirs, salt caverns, and saline aquifers. The increasing number of depleted shale gas reservoirs may be good candidates for H2 storage. In this work, we analyze the potential of H2 storage in depleted gas reservoirs using Monte Carlo (MC) simulations. The competitive adsorption of a methane-hydrogen (C1-H2) system under nanoscale conditions is investigated, including the effects of pore size, temperature, pressure, boundary material, and fluid composition. Our results show that C1 is preferentially adsorbed in a C1-H2 system. C1 forms the adsorption layer near the boundary surface, while H2 molecules are freely distributed in the pore. The fluid distribution indicates that H2 can be easily produced during H2 recovery processes, which contributes to H2 storage in depleted shale gas reservoirs. In addition, the effect of water on C1-H2 competitive adsorption is analyzed. The strong interactions between water and boundary atoms force C1 molecules away from the adsorbed region. This work provides a foundation for hydrogen storage in depleted shale gas reservoirs at a molecular level.

Feasibility of hydrogen storage in depleted shale gas reservoir: A numerical investigation

Due to the low operation cost, high containment security, and large storage capacity, depleted shale gas reservoirs are considered as promising options for large-scale hydrogen storage. However, its feasibility has not been systematically examined yet. It is still unknown about whether the deliverability (injection/withdrawal) capacity could meet the energy supply/demand and how the depletion time, cushion gas selection, injection/withdrawal strategy will influence the performance of this scenario.Therefore, we present a numerical compositional modelling investigation on hydrogen storage in a partially depleted Fuling shale gas reservoir in China. The results demonstrated that: 1) a high injection/withdrawal capacity could be achieved through a single shale play pad in the area of interest as approximately 5.4 × 108 Sm3 hydrogen could be stored and 3 × 108 Sm3 could be recovered in each cycle (equal to 0.54 TWh of power output). 2) CH4 production is inhibited once hydrogen storage project is performed, an early depletion time could significantly reduce CH4 production but slightly improve H2 withdrawal. 3) Cushion gas injection is beneficial to reducing H2 loss and enhancing 2.8% H2 recovery, while the main drawback of this operational measure is an increase in capital cost in gas separation due to lower H2 purity in the produced gas.This work demonstrates that shale gas reservoir is a promising candidate for hydrogen storage, which is beneficial to the implementation of large-scale hydrogen economy and the operation of hydrogen supply chain.

Molecular Simulation of Hydrogen-Shale Gas System Phase Behavior under Multiscale Conditions: A Molecular-Level Analysis of Hydrogen Storage in Shale Gas Reservoirs

To reduce carbon emissions, hydrogen (H2) has been considered an important energy carrier, since its combustion only generates water. With the development of shale gas, depleted shale gas reservoirs might be good candidates for H2 storage. However, the mechanism of H2 storage in depleted shale gas reservoirs is not clearly understood. Therefore, in this work, we apply Monte Carlo simulation to analyze the compositional distribution and phase behavior of the H2–shale gas (H2–SG) system under multiscale (bulk + nanoscale) conditions. Our molecular simulation results show that compositional heterogeneity exists between the bulk region and the nanopores. The bulk fluid has a higher percentage of H2 while more hydrocarbons are present in nanopores. For the fluids in nanopores, hydrocarbons are adsorbed near the boundary while H2 molecules are freely distributed, which makes H2 molecules more likely to be released to the bulk region. The compositional heterogeneity and hydrocarbon adsorption collectively lead to a high percentage of H2 in the bulk fluid. Since the bulk fluid is produced during the extraction process, the high percentage of H2 in the bulk fluid means a high purity of H2 in the extracted fluid, which can be a positive factor for H2 storage in shale gas reservoirs. An increase in the volume percentage of nanopores can increase the H2 purity in the extracted fluid.

An integrated model for carbon geo-sequestration considering gas leakage

Carbon geo-sequestration is a promising method for mitigating global warming and climate change. Depleted shale gas reservoirs with high adsorption capacities, excellent sealing properties, and complete infrastructure are potential sites for CO2 storage. However, hydraulic fracturing and extensive CO2 injection can result in fault reactivation, leading to CO2 migration and an increased risk of environmental contamination. Given this problem, a partially permeable boundary is introduced to characterize permeable faults. Herein, a novel methodology based on rate transient analysis that considers CO2 adsorption, diffusion, and leakage is proposed for evaluating the CO2 storage capacity of depleted shale gas reservoirs. The analytical solution for a multiple fractured horizontal well with finite conductivity is derived from the principle of potential superposition, Laplace transform, and correction functions. Subsequently, according to the analytical solutions, a rapid and robust CO2 storage capacity assessment technique is established. Using field data of the Marcellus shale, a sensitivity analysis is performed to analyze the effects of the reservoir and well parameters on the injection performance, carbon storage potential, and CO2 leakage risk. The results indicate that the proposed model is consistent with previously reported semi-analytical models and numerical simulations. The injection rate and cumulative leakage ratio increase with the leakage ratio, resulting in gas migration and an increased risk of leakage. Reservoirs with large drainage radii, high Langmuir volumes, and small Langmuir pressures are suitable for carbon sequestration, significantly increasing the adsorption capacity and reducing the leakage risk. In this study, a novel method is used to calculate the analytical solution for multiple fractured horizontal wells, which allows a rapid and practical CO2 geo-sequestration capacity assessment for CO2 storage projects.

A New Method Based on Boundary Element Method to Appraise CO2 Geological Storage Potential in Depleted Shale Gas Reservoirs

In recent years, greenhouse gases have increased in the atmosphere, and climate change concerns have triggered global efforts to find solutions for CO2 capture, separation, transport, and storage. Geological sequestration in the depleted unconventional reservoir is an effective measure to reduce the atmosphere’s CO2 content. The exact evaluation of the CO2 storage capacity can verify the feasibility of storing carbon dioxide and parameter optimization. A reasonable boundary element method to estimating the CO2 storage capacity of depleted shale gas reservoirs considering arbitrarily shaped boundaries is introduced. Firstly, the physical model with fracture networks is built based on the microseismic data. Then, the flow equation including the matrix and fracture can be obtained considering adsorption, and the star-delta transformation is used to deal with interconnected fracture segments. The point source function with an infinite boundary can be obtained after the Laplace transform method. Finally, the semianalytical flow solution is obtained by using the boundary element method in the Laplace region. Moreover, the results have a high agreement with commercial software for the regular boundary. The sensitivity of relevant parameters is analyzed by this method, and the importance of considering the boundary shape is emphasized. This method can evaluate the CO2 storage capacity of formation with the irregular boundary and is regarded as the guide of parameter optimization in CO2 storage.

CO2 Capture and Storage Performance Simulation in Depleted Shale Gas Reservoirs as Sustainable Carbon Resources

Underground carbon capture and sequestration (CCS) is a useful technique for separating this kind of greenhouse gas from atmosphere and store it under the surface of the earth. As a matter of fact, CO2 can be transferred to underground petroleum reservoirs which are initially contained oil and gas, or aquifers which are initially saturated with water. This kind of CCS takes place using an injection well which is drilled from surface to the target underground bedrocks. A shale gas reservoir (SGR) is a type of petroleum gas reservoir in which natural gas is stored in ultra-tight pores of the shale rock. In this study, a flow modeling analysis in SGR with a multi-stage fractured horizontal well (MSFHW) is conducted using numerical simulation. In this shale layer, a horizontal well is drilled and several transverse hydraulic fractures, for increasing the flow efficiency between the well and porous medium, are created. The studied SGR – a depleted reservoir acting as a macroscopic sustainable material for the CCS – is initially saturated with methane gas, and carbon dioxide is required to be injected for the storage. The most outstanding results of this study is about sensitivity analyses for SGR permeability with different conditions of gas adsorption and stress-dependent permeability which are from important features of SGRs. The results show a minor reduction in cumulative gas injection due to the effect of stress-dependent permeability in all measures for reservoir permeabilities. Furthermore, gas sorption shows a considerable positive correlation with CO2 storage response in high-permeability SGR and a minor increasing effect on SGRs with lower permeability values.

Revisiting field estimates for carbon dioxide storage in depleted shale gas reservoirs: The role of geomechanics

The prospects for CO2 sequestration in depleted shale gas formations are widely studied. Reported studies offer quantitative predictions of ultimate storage capacity as well as CO2 injection rate for a typical injection site or on an areal basis. Reported estimates for the ultimate storage capacity in various shales vary from 10 Gt to 50 Gt. In recent analysis, a numerical hydrodynamic model, neglecting geomechanical effects, was calibrated to historical gas field production data from various shales, and applied to estimate both injection capacity and rate. The projected site injection rates fell up to two orders-of-magnitude short of anticipated capture rates. It is hypothesized that geomechanical deformation, particularly within fractures, under depletion and pressurization can lead to significant variation in production and injection rates. This work revisits the field estimates by utilizing a coupled hydrodynamic and poromechanical model. History matching of field production data is performed using Ensemble Smoother with Multiple Data Assimilation (ES-MDA), and a Bayesian model-selection approach is applied. The results indicate that while both models are equally viable from the perspective of Bayesian model-selection, the coupled model estimates indicate a two-fold increase of capacity over those of the flow model. Moreover, the projected injection rates incorporating deformation are enhanced by two-folds at early times and by up to five-folds at later times.

Swelling of Shales by Supercritical Carbon Dioxide and Its Relationship to Sorption.

Shale gas is a promising energy source offering additional energy security over concerns of fossil fuel depletion. Injecting CO2 into depleted shale gas reservoirs might provide a feasible solution for CO2 storage and enhanced gas recovery. However, shale strain caused by the CO2 injection as well as CO2 sequestration in the reservoir needs to be considered during shale gas production. For this purpose, this paper examines the adsorption capacities, CO2-induced swelling, and He-induced strain of shales at 0–16 MPa and 35–75 °C. The maximum excess adsorption at different temperatures correlated with the bulk phase density: as the CO2 temperature increased, the maximum excess adsorption density decreased. The density of the adsorbed phase, obtained using the Dubinin–Radushkevich model, was used to fit the excess adsorption data. At low pressure, the CO2-induced strain on shale was caused by the gas adsorption, whereas at high pressure, it was caused by gas pressure. The absolute adsorption linearly correlated with the adsorption-induced strain.

A real options approach to production and injection timing under uncertainty for CO2 sequestration in depleted shale gas reservoirs

Depleted shale gas reservoirs may be candidates for conversion to injection wells for the long-term geologic storage of CO2, but the decision to transition from production to injection depends on economic and policy factors that may be uncertain. This paper aims to comprehend the uncertainty inherent to the underlying assumptions of CO2 sequestration and their impact on the injection decision. We view and analyze the production to injection transition decision as a kind of options problem, where the owner of a producing well can choose to exercise the option to stop producing natural gas and start injecting CO2. Our approach integrates a detailed reservoir model for shale-gas production and CO2 injection in the Marcellus shale formation with a multi-period decision problem under uncertainty in future prices for CO2 and produced natural gas. With no uncertainty, the modeling framework is able to identify the optimal timing of the transition to CO2 injection as a function of natural gas prices and a hypothetical CO2 price. We find that a CO2 price of approximately $15 per tonne to be needed in order to incentivize a producer to transition to CO2 injection earlier. If these prices are uncertain, we find that the option to delay CO2 injection has value even when CO2 prices are relatively high and natural gas prices are low, although the option value is highly sensitive to the choice of discount rate and the option value to delay injection is generally very low when CO2 prices are $20/tonne or higher. Our modeling suggests that commitment in carbon pricing regimes is of equal importance to the choice of the price level.

CO2 sequestration coupled with enhanced gas recovery in shale gas reservoirs

Carbon capture and storage in depleted shale gas reservoirs offers an opportunity to utilize CO2 for enhanced gas recovery while providing access to fossil fuels. To evaluate CO2 sequestration coupled with enhanced gas recovery (CO2-EGR), we have developed a model that takes into account all the major contributing mechanisms in shale gas dynamics including viscous flow, gas slippage, Knudsen diffusion, competitive adsorption of different components, pore size variation and real gas effect. The CO2-EGR process is divided into periods of primary production, CO2 injection, soaking and secondary simultaneous production of CO2 along with other natural gas components. Numerical simulations are conducted to study the feasibility of CO2 sequestration and enhanced gas recovery and analyze the response of the shale gas reservoir to input variables including reservoir pressure, temperature and intrinsic permeability. The results show that the stronger adsorption of CO2 over CH4 molecules to shale surface is the main influencing mechanism on CO2 sequestration. It is shown that 30–55% percent of the injected CO2 can be trapped as adsorbed phase in shale while providing 8–16% incremental gas recovery. Comparing trapping efficiency of CO2-EGR with other methods of accelerating CO2 dissolution in deep saline aquifers, adsorbed phase trapping is promising.

Influence of Microcracks on Flow and Storage Capacities of Gas Shales at Core Scale

This work investigates the interplay of gas transport in the microcracks and matrix of shale using He and $$\hbox {CO}_2$$ via transient upstream pressure-pulse-decay experiments. The microcracks are natural in the sense no laboratory pretreatment created them. A novel setup of the pressure-pulse-decay experiment was used to determine the storage and flow capacities simultaneously. Experimentally, the pressure signals are used to define time-dependent pore volume partitioning between the microcracks and the matrix. A dual continuum simulator is constructed to decouple the flow and storage capacities at early time where the gas flows simultaneously in both media. A history-matching process quantifies the pore volume partitioning of the microcracks and matrix, the permeability in the microcracks, and the diffusivity of gas in the matrix. A series of experiments were conducted on four shale samples from Eagle Ford and Haynesville shale plays at constant net effective stress of 500 psi and at increasing net effective stresses of 500, 1000, and 2000 psi. Results show that the pore volume of the microcracks in sample 180Ha (Eagle Ford) was from 8.0 to 24.1% of the total pore volume in all experiments at constant and variable net effective stresses. The Haynesville samples (TWG 1-3 & 3-3) had between 68.9 and 87.0% of the total porosity in the microcracks while the remaining percentage represents the pore volume in the matrix. These proportions are related to the magnitude of permeability and void volumes in the system. The values of Klinkenberg-corrected permeability estimated using He vary between 396 and 1.6 $$\upmu \mathrm{D}$$ . The role of adsorption was also investigated using $$\hbox {CO}_2$$ in the same experimental apparatus and conditions. It was found that the influence of pore volume partitioning is suppressed by the large adsorption capacity in the shale samples. It was found that adsorption occurs in the microcracks in permeabilities less than 50 $$\upmu \mathrm{D}$$ along with adsorption in the matrix. For permeabilities greater than that value, adsorption had no importance on microcracks. Adsorption in both media required different adsorption–pressure functions. The $$\hbox {CO}_2$$ permeability was found to be smaller than the He permeability by 2–3 factors. $$\hbox {CO}_2$$ injection into the core caused a reduction in permeability that was observed with He injection after $$\hbox {CO}_2$$ flooding. The He permeability dropped by a factor of 2–3. This permeability hysteresis is attributed to the reduction in pore size accessed by the gas. This observation provides another reason why $$\hbox {CO}_2$$ storage in depleted shale gas reservoirs is practical. Reduction in gas permeability may be essential to keep $$\hbox {CO}_2$$ underground for as long as possible.

CO2 Storage Capacity for Multi-Well Pads Scheme in Depleted Shale Gas Reservoirs

As a promising technology to improve shale gas (SG) recovery and CO2 storage capacity, the multi-well pads (MWPs) scheme has gained more and more attention. The semi-analytical pressure-buildup method has been used to estimate CO2 storage capacity. It focuses on single multi-fractured horizontal wells (SMFHWs) and does not consider multi-well pressure interference (MWPI) induced by the MWPs scheme. This severely limits the application of this method as incidences of multi-well pressure interference have been widely reported. This paper proposed a new methodology to optimize the injection strategy of the MWPs scheme and maximize CO2 storage capacity. The new method implements numerical discretization, the superposition theory, Gauss elimination, and the Stehfest numerical algorithm to obtain pressure-buildup solutions for the MWPs scheme. The solution by the new method was validated with numerical simulation and pressure-buildup curves were generated to identify MWPI. Using the new method, we observed that the fracture number and fracture half-length have a positive influence on CO2 storage capacity. Both can be approximately related to the CO2 storage capacity by a linear correlation. For a given injection pressure, there is an optimal fracture number; the bigger the limited injection pressure, the smaller the optimal fracture number. Stress sensitivity has positive influences on CO2 storage capacity, thus extending the injection period would improve CO2 storage capacity. This work gains some insights into the CO2 storage capacity of the MWPs scheme in depleted SG reservoirs, and provides considerable guidance on injection strategies to maximize CO2 storage capacity in depleted SG reservoirs.

Quantitative determination of abandonment pressure for CO2 storage in depleted shale gas reservoirs by free-simulator approach

Abandonment pressure of shale gas reservoirs has been in the center of attention to evaluate the CO2 storage in such reservoirs. However, the evaluation of abandonment pressure in shale gas reservoirs is not clearly defined. To quantitatively determine the abandonment pressure for CO2 storage in depleted shale gas reservoirs, we introduced two effective and reasonable semi-analytical models, named pressure transient analysis (PTA) and rate transient analysis (RTA), based on a free-simulator approach. Firstly, by line source function, CO2 seepage models for an injection well with constant injection rate or constant injection pressure were simultaneously proposed in consideration of gas adsorption, diffusion flow, stress sensitivity and non-Darcy flow effects. Then, we solved seepage models using Laplace transformation, perturbation method, superposition principle and numerical discretization method, thus obtained transient-pressure and transient-rate solutions of the injection well. Further, we compared the proposed mathematical models with existing models. Furthermore, we systematically examined the sensitivity of the parameters, thereby constraining the intrinsic uncertainty to evaluate the abandonment pressure. Finally, we applied the proposed method to study a real case from Sichuan Basin in China, thus demonstrating the promising prosperity of this new quantitative determination of abandonment pressure for CO2 storage in depleted shale gas reservoirs.Our results showed that the maximum difference between our proposed method and numerical method was lower than 5%, suggesting a good agreement between the two methods. Moreover, our results also showed that free-simulator approach gave much faster calculation speed compared to numerical method. As a result, we provided a framework for the quantitative determination of abandonment pressure, by coupling pressure transient analysis (PTA) and rate transient analysis (RTA) during CO2 injection at constant injection pressure and injection rate. Moreover, our results also showed that the abandonment pressure has power law relationship with the injection pressure using PTA method, and the abandonment pressure has logarithm relationship with CO2 injection volume using RTA method.

Comprehensive application of semi-analytical PTA and RTA to quantitatively determine abandonment pressure for CO2 storage in depleted shale gas reservoirs

Recent studies suggest the possibility of CO2 sequestration in depleted shale gas reservoirs, motivated by large storage capacity estimates in these formations. Although various approaches have been proposed to evaluate and estimate CO2 storage capacity and even almost all of researches mainly focus on the calculation of storage capacity at the present time, questions remain regarding the quantitative determination of abandonment pressure for a depleted shale gas reservoir, which is a key joint between shale gas recovery and CO2 storage operation. Also the determination of abandonment pressure is the inversion problems of estimation of CO2 capacity. Therefore, in this paper, to quantitatively determine the abandonment pressure and mathematically analyze related impacts of dynamic parameters on it, two semi-analytical models of pressure and rate transient analysis are simultaneously proposed for the closed outer boundary condition, without the assumption of sequential flow between the three contiguous media. Adsorption, desorption, diffusion flow, stress sensitivity and non-Darcy flow effects are simultaneously considered. Besides, a new modified Langmuir isotherm equation of CO2 is initially established to consider the impacts of residual adsorption shale gas. Laplace transformation, source function, perturbation transformation method, superposition principle and numerical discretion method are employed to effectively solve these new models. Laplace solutions are inverted into real time space with stehfest numerical inversion algorithm. Numerical simulation and existing models are also simultaneously conducted to validate this proposed mathematical models. Based on this new solution, some crucial dynamic engineering parameters, including abandonment pressure and non-Darcy flow, are creatively analyzed combining pressure transient analysis (PTA) and rate transient analysis (RTA) For two kinds of CO2 injection control: constant injection pressure and constant injection rate, it is the essence of this paper that typical chart referring quantitative determination of abandonment pressure is originally established via pressure transient analysis (PTA) and rate transient analysis (RTA). Via regression method using synthetic and real data, results mathematically show that for PTA method, the abandonment pressure has exponent relationship with the injection pressure, however, for RTA method, the abandonment pressure has logarithm relationship with CO2 injection volume. Finally, well testing of gas production data, micro seismic date and core analysis allow for formation parameter estimation, two real shale gas wells from Sichuan Basin in China are selected to show the promising application prosperity of the new performance analysis and quantitatively determination of abandonment pressure for CO2 storage in depleted shale gas reservoirs.

Analysis of carbon dioxide sequestration in shale gas reservoirs by using experimental adsorption data and adsorption models

For carbon dioxide (CO2) sequestration in depleted shale gas reservoirs or CO2 injection as an enhanced shale gas recovery technique, it is important to understand the adsorption mechanism in these reservoirs. In this study, experimental adsorption measurements for Dadas shale samples were conducted at 25 °C, 50 °C, and 75 °C up to approximately 2000 psia by using pure CO2 (maximum adsorption capacity 0.211 mmol/g at 25 °C) and pure methane (CH4) (maximum adsorption capacity 0.0447 mmol/g at 25 °C). By using Langmuir isotherm and Ono-Kondo lattice models (three-layer and monolayer), experimental adsorption results were evaluated and adsorption isotherms were constructed. It was concluded that Ono-Kondo monolayer model is really capable of fitting adsorption isotherms, especially at high pressures for CO2 adsorption. For initial gas-in place calculations, the equations used by the help of Langmuir isotherm were modified with Ono-Kondo monolayer model and proposed to calculate the amount of CO2 that might be stored as adsorbed and free gas in depleted shale gas reservoirs. For the case in this study, it was calculated that adsorbed gas concentration changes from 39.2% to 71.8% between 5000 psia and 500 psia. Moreover, binary mixture Ono-Kondo monolayer model was used to evaluate the adsorption isotherm of CO2CH4 mixtures by using their pure adsorption experimental data. This data is useful if there is a purpose to inject CO2 as an enhanced shale gas recovery technique because of the adsorption capacity difference between CH4 and CO2.

Techno-economic assessment of industrial CO2 storage in depleted shale gas reservoirs

The long-term storage of carbon dioxide (CO2) via injection into deep geologic formations represents a promising technological pathway to reducing greenhouse gas emissions to the atmosphere. Geologic storage in deep saline aquifers has been studied extensively, and the injection of CO2 for enhanced oil recovery (EOR) from conventional (porous and permeable) formations has been practiced for decades. This study is focused on developing a preliminary assessment of the economic feasibility of storing CO2 in depleted unconventional natural gas-bearing shale formations. Using a surrogate reservoir model (SRM) and a flexible environment for techno-economic analysis, this paper presents site-scale estimates of long-term CO2 sequestration costs in depleted shale gas formations and discussion of the likely major cost drivers. This analysis focuses on the transportation of CO2 from industrial point sources in the Pennsylvania Marcellus Shale region, and the transition of Marcellus wells from production to CO2 injection. This approach couples techno-economic analysis with reservoir simulation models to estimate costs associated with transportation, injection, CO2 separation and post-injection monitoring of CO2 storage permanence from large industrial point sources in depleted shale-gas reservoirs. We also consider potential revenue from incremental CH4 recovery (effectively enhanced gas recovery) in reservoir scenarios where such production is significant. The techno-economic model boundary includes pipeline transport from an industrial source (excludes the cost of capture of CO2 at that source), site preparation and CO2 flooding operations, and long-term monitoring and post-injection site care (PISC) at the storage site. Under an operational scenario where a Marcellus shale gas well is in primary production for 42years prior to the initiation of CO2 injection, it is estimated that CO2 could be transported and stored at a levelized cost of $40–$80 per metric tonne, in present value terms. These costs are shown to be highly sensitive to assumptions regarding well spacing, bottomhole pressure, CO2 transport distance and the future price of natural gas. In most of the scenarios considered, transportation and injection costs were dominant factors, while CO2 separation, pore space acquisition and post-injection site care/monitoring did not significantly influence levelized costs.