Enhanced Gas Recovery Research Articles

A two-phase, multi-component model for efficient CO2 storage and enhanced gas recovery in low permeability reservoirs

Introduction: Carbon dioxide (CO2) enhanced gas recovery represents a viable strategy for sequestering CO2 while concurrently augmenting gas production from subsurface reservoirs. Gas reservoirs, as inherent geological formations, are optimal repositories for gaseous compounds, rendering them suitable for CO2 storage. Nevertheless, the economic viability of pure CO2 storage necessitates integration with oil and gas recovery mechanisms to facilitate widespread CO2 utilization.Method: This study addresses the complexities of CO2 enhanced gas recovery through a comprehensive approach that combines theoretical model and numerical simulations. A numerical model is developed to simulate three-component diffusion involving CO2, and methane (CH4) in a two-phase system comprising gas and water.Results: The investigation systematically explores the process of enhanced CH4 extraction and CO2 injection into the reservoir and examines the influencing factors on extraction. Simulation results reveal a power-law decrease in CH4 production rate, stabilizing at a constant extraction rate. Enhanced CH4 extraction benefits from increased porosity, with higher porosity levels leading to greater CH4 extraction. Permeability augmentation positively influences CH4 production, although with diminishing returns beyond a certain threshold. The CO2 injection rate shows a direct proportionality to CH4 production. However, elevated CO2 injection rates may increase reservoir pressure, potentially causing cap rock damage and CO2 gas flushing.Discussion: This study contributes valuable theoretical insights to the field of CO2 enhanced gas recovery engineering, shedding light on the intricate dynamics of multi-component fluid transport processes and their implications for sustainable CO2 utilization.

System and multi-physics coupling model of liquid-CO2 injection on CO2 storage with enhanced gas recovery (CSEGR) framework

Injecting CO2 into gas reservoirs can achieve CO2 Storage with enhanced gas recovery (CSEGR). The development of liquid-CO2 injection has the characteristics of high injectability, high mobility ratio, and low diffusion coefficient. Therefore, this paper established a wellbore-reservoir-thermo-hydro-mechanical-diffusion (WR-THMD) multi-physics fully coupled model of the wellbore-reservoir system, and verified the model based on field and experimental data. The mass transfer, heat transfer, and gas physical property changes in the wellbore and reservoir during the injection of liquid-CO2 were studied. The impact of different engineering parameters on improving CH4 recovery and CO2 storage is also discussed. The results show that the impact of the wellbore on the physical properties and phase state of CO2 is crucial. The injection of liquid-CO2 is beneficial to the storage of CO2 and the displacement of CH4. Lowering the injection temperature will slightly improve the injectability of liquid-CO2 and increase the CO2 storage rate by 5.13%. Using a high injection mass flow rate will effectively raise CH4 recovery rate by 15.60%, but it will weaken the injectability of CO2 and cause CO2 to break through in the production well prematurely. The research results provide important suggestions and theoretical support for the application of liquid-CO2 injection on CSEGR.

Evaluation of CO2 storage and enhanced gas recovery potential in gas shale using kerogen nanopore systems with mesopores and micropores

With the continuous development of shale gas, CO2 storage in shale gas reservoirs has gained significant attention due to the massive available space in these reservoirs. These shale formations exhibit a complex pore structure with micropores (<2 nm) and mesopores (2–50 nm), which profoundly influence gas sorption behaviors. This work used grand canonical Monte Carlo to study the sorption behavior of CH4, CO2, and their binary mixtures (from 1:9 to 9:1) in kerogen nanopore systems with mesopores and micropores at 327 K and pressures ranging from 1 to 50 MPa. The kerogen nanopore system with mesopores and micropores faithfully describes sorption isotherms. The adsorption profile highlights the adsorption characteristics and relative contribution of mesopores and micropores. The molar ratio of CO2 to CH4 in the replacement process is greater than 1, indicating the possibility of achieving negative emissions by storing CO2 in shale gas reservoirs. The extraction ratio reveals that CH4 in micropores is more easily extracted. As for CO2 storage in shale gas formation, the sorption phase dominates at low pressure, while the free gas phase becomes more significant at higher pressure. At a reservoir pressure of 35 MPa, approximately 125 tons of CO2 can be stored in 1000 m3 of shale gas formation. Using CO2 huff-n-puff technology, the recovery factor more than doubles compared to pressure drawdown. While pressure drawdown primarily extracts CH4 from the free gas phase, CO2 injection extracts CH4 from the sorption phase, particularly micropores. This research provides valuable insights into the competitive sorption behavior of CH4 and CO2 in shale nanopore systems for further development of CO2 storage and enhanced gas recovery technologies.

Development and field application of a jetting and helical combination tool

Liquid loading occurs in gas wells after a period of production, and the vortex drainage gas recovery technology can alleviate this problem by removing liquid. To substantially enhance the efficiency of this technology, a novel tool combining jetting and helical mechanisms has been introduced. To validate its effectiveness, a laboratory system for detailed analysis of pressure drops by using various tools at multiple gas flow rates has been set up. The analysis approach encompasses both single-factor and orthogonal analyses of tool structure parameters to find out the optimal tool structural parameters under different operating conditions. Consequently, a correlation between the gas flow rates observed in controlled laboratory environments and those in actual gas wells has been established. The study indicates that the tool’s main structural parameters significantly impact pressure drops along the wellbore. Furthermore, it is evident that distinct well profiles require unique tool setups to minimize such pressure drop. Field tests of the optimized tool have shown notable enhancements: The average gas flow rate increased by 25.9%, reaching 5.39 × 104 m3/d (1.90 × 106 scf/d), while the average liquid flow rate increased by 20.1%, reaching 1.46 m3/d (9.18 bbl/d). These results highlight the superior drainage stimulation effect of the new jetting and helical combination tool, presenting novel insights and methodologies for enhancing gas recovery in liquid-loaded gas wells.

Pore Evolution Law and Gas Migration Characteristics of Acidified Anthracite in Liquid CO2‐ECBM: An Experimental Study

The high gas pressure, low permeability, and strong gas absorption of coal seams in China complicate gas extraction, severely restricting the efficient development of coalbed gas. Liquid CO2 (LCO2) has a dual effect of cracking and enhancing the permeability of coal rock, thus, enhancing gas recovery. In this study, experimental testing and comparative analyses were performed to analyze the LCO2 acidification of antireflection coal, for which reference and variable experimental groups were designed. The acidification effect was quantitatively analyzed by examining changes in the pH value of the reaction solution, mineral content of coal, and pore structure during the experimental process. The experimental results indicated that a higher pressure resulted in a greater amount of CO2 being dissolved and a stronger acidity of the reaction water sample. As the reaction time increased, the minerals in the coal gradually dissolved and more H+ ions in the solution were consumed. The calcite (carbonate) and illite (clay mineral) contents significantly decreased, which is the main reason for the change of coal pore structure. The minerals on the pore surface of coal react with (CO2–H2O) weak acid, which increases the development of pore branches, improves the complexity of coal pores, and roughens the pore surface. Acidification significantly increases the number of micropores (&lt;10 nm) and small pores (10–100 nm) in coal; furthermore, pore development is simple, the surface is smooth, and the pore connectivity is improved, which makes this part of pores have fractal characteristics. CO2–H2O–coal acidification increases the pore volume corresponding to the CO2/CH4 gas slippage flow in coal and strengthens the mass and energy transfer of CO2/CH4 in coal. CO2 can enter more pores than CH4 and displace the adsorbed and free CH4 in the pores.

Enhanced Gas Recovery for Tight Gas Reservoirs with Multiple-Fractured Horizontal Wells in the Late Stages of Exploitation: A Case Study in Changling Gas Field

To initially improve the gas production rate and shorten the payback period for tight gas reservoirs, the multiple-fractured horizontal well (MFHW) model is always applied. However, in the late stages of exploitation, it is difficult to adopt reasonable measures for enhanced gas recovery (EGR), particular for continental sedimentary formation with multiple layers, and efficient strategies for EGR in this type of gas field have not yet been presented. Therefore, in this paper, a typical tight gas reservoir in the late stages of exploitation, the Denglouku gas reservoir in Changling gas field, in which MFHWs were utilized and contributed to the communication of the higher Denglouku formation (0.34 mol% CO2) and lower Yingcheng formation (27 mol% CO2) during hydraulic fracturing, is studied comprehensively. Firstly, alongside the seismic, logging, drilling and experimental data, 3D geological and numerical simulation models are developed. According to the differences in CO2 mole fractions for different formations, the gas production rate of MFHWs produced from Denglouku formation is accurately calculated. Then, the well gas production rate (WGPR) and the well bottom-hole pressure (WBHP) history are matched with the calculated values, and thus the types of remaining gas are provided through the fine reservoir description. Finally, in a combination of gas recovery and economics, the optimal infill well type and the adjustment scheme are determined. The results show that there are three main categories of remaining gas, which are areal distribution, abundant points, and marginal dispersion, and the ratios of reaming gas reserve for these three types are 80.3%, 4.2%, and 15.5%, respectively. For the tight gas reservoir developed by MFHWs with parallel and zipper patterns, the best infilling well type is the vertical well. The combination of patching holes, sidetracking, infilling and boosting can obtain the highest gas recovery, while the scheme with patching holes and sidetracking has the best economic benefits. To balance the gas recovery and economics, the measurement of patching holes, sidetracking and infilling with vertical wells is utilized. In the final production period, compared with the basic schemes, the gas recovery can increase by 5.5%. The primary novelty of this paper lies in the determination of the optimal infilling well types and its presentation of a comprehensive adjustment workflow for EGR in tight gas reservoirs. The conclusions in this paper can provide some guidance for other similar tight gas reservoirs developed with MFHWs in the later period.

Key technologies and orientation of EGR for the Sulige tight sandstone gas field in the Ordos Basin

The Sulige Gas Field in the Ordos Basin is the largest tight gas field in China, with proved reserves exceeding 2 × 1012 m3. As the main contributor to gas production in PetroChina Changqing Oilfield Company, The Sulige Gas Field is in the stage of stable production. Maximizing the stable production period is a focus and challenge for the gas field now. To address a series of problems influencing the efficient development of Sulige gas field, such as large-scale remaining gas reserves between wells/layers and low ratio of employed reserves, the main technologies for enhanced gas recovery (EGR) of tight gas reservoirs were developed by multidisciplinary research with respect to development geology, reservoir engineering, drilling and production process, and surface gathering and transportation. Experiments were conducted on reservoir description and remaining gas characterization, well pattern thickening optimization, vertical well separate-layer fracturing, horizontal-well multi-stage multi-cluster volume fracturing for their improvement and upgrading. The orientation of EGR for tight gas reservoirs is proposed. The following results are obtained. First, well pattern thickening optimization is the most important EGR method, which can increase the recovery rate by more than 6%. Second, based on continuous upgrading and promotion, either of reservoir stimulation technology and drainage gas recovery technology can increase the recovery rate by more than 2%. The gathering and transportation technology which further reduces the wellhead pressure can increase the recovery rate by about 1.5%. Third, the EGR technology should be oriented to maximize the quantity of employed reserves, especially by way of new technologies such as fine remaining gas characterization, well pattern/type optimization, cross-layer fracturing of a multi-thin-layer reservoir by horizontal wells, intelligent drainage gas recovery, and multi-stage pressurization. It is concluded that the development of key EGR technologies will help increase the recovery rate of The Sulige Gas Field by 10%–15%, and will provide an effective support for The Sulige Gas Field to maintain the production at 300 × 108 m3/a for a long term and for the Changqing gas province to increase the production to 500 × 108 m3/a, which will ultimately ensure the national energy security.

Enhancing Gas Recovery in Tight Dolomite Reservoirs: A Study of Water-Lock Damage and Chemical Drainage

The Lower Paleozoic Ordovician strata within the Ordos Basin harbor dolomite gas reservoirs are characterized by low porosity (0.98% to 14.2%) and low permeability (0.001 mD to 2.8 mD). Gas extraction from these reservoirs is frequently impeded by water lock due to the intrusion of water-based drilling fluids and the accumulation of formation water, which increase water saturation near the wellbore and significantly decrease gas permeability. This research is pivotal in elucidating water-lock mechanisms and developing water-unlocking strategies for such tight gas reservoirs. Comprehensive analysis through wettability tests, spontaneous imbibition, high-speed centrifugal drainage, and nuclear magnetic resonance (NMR) revealed that Jingbian gas field rocks are predominantly water-wet with a spontaneous imbibition water saturation of 60% to 80%, indicating a high propensity for water lock. The pore structure, mainly within the 200 to 300 nm range, presents challenges as high-speed centrifugation achieves only 70% to 80% water saturation displacement, with a drainage rate of about 20% to 30% and a drastic decline in gas permeability by several orders of magnitude. This study identifies the surfactant sodium dodecyl benzene sulfonate (SDBS) as an optimal agent for enhancing water displacement and gas production. At a 0.1% concentration, SDBS improves drainage rate and permeability by 58.5% and 69.42%, respectively, demonstrating its efficacy in mitigating water lock and enhancing recoverability in tight dolomite reservoirs. These findings serve as a scientific guide for augmenting production in similar geological settings.

Advancing "Carbon Peak" and "Carbon Neutrality" in China: A Comprehensive Review of Current Global Research on Carbon Capture, Utilization, and Storage Technology and Its Implications.

Carbon capture, utilization, and storage (CCUS) technology plays a pivotal role in China's "Carbon Peak" and "Carbon Neutrality" goals. This approach offers low-carbon, zero-carbon, and even negative-carbon solutions. This paper employs bibliometric analysis using the Web of Science to comprehensively review global CCUS progress and discuss future development prospects in China. The findings underscore it as a prominent research focus, attracting scholars from both domestic and international arenas. China notably leads the global landscape in terms of research paper output, with the Chinese Academy of Sciences holding a prominent position in total published papers. The research predominantly centers on refining geological storage techniques and optimizing oil and gas recovery rates. Among the CCUS pathways, enhanced oil recovery technology stands out due to its relative maturity and commercial applicability, particularly within the conventional oil and gas reservoirs. The application potential of enhanced gas recovery technology, especially in the Sichuan and Ordos Basins in China, necessitates robust research and demonstration efforts. Within China's current energy landscape, "Blue Hydrogen" emerges as the primary solution for hydrogen production in conjunction with CCUS technology. The underground coal gasification approach holds significant promise as a hydrogen production avenue, albeit with inherent ecological and environmental challenges tied to geological storage that require meticulous consideration. The establishment of effective risk identification and evaluation methodologies for geological storage is imperative. The trajectory ahead involves a strategic convergence of policy, technology, and market dynamics to enhance China's CCUS policy framework, legislative framework, standardization initiatives, and pioneering technological advancements. These collective efforts converge to outline an exclusive development pathway in China. This study assumes a pivotal role in accelerating CCUS technology research and deployment, enhancing oil and gas recovery efficiency, and ultimately realizing the overarching goals of a "Dual Carbon" future.

Numerical study on the effectiveness of directional well with multiple hydraulic slots for enhanced gas recovery in deep coal seam

Coalbed methane production failures through hydraulic fracturing in the Linxing gas field in China have encountered significant setbacks, hindering efforts to enhance the recovery of deep CBM reserves in the region. To address this challenge, we investigate the potential of directional wells with multiple hydraulic slots as a stimulation technology for deep coalbed methane extraction. This study presents two numerical models to evaluate the effectiveness of this technology. The first model is a continuum damage numerical model based on the Material Point Method, which simulates large deformations and complex contact behaviors induced by hydraulic slotting in the deep coal seam. The second model is a wellbore-pore coupling model to simulate the gas extraction process. We verified both numerical models against theoretical and experimental results. We conducted a case study in the Linxing gas field using these models. The investigation assessed stress relief, gas desorption, and permeability enhancement around a large deformed hydraulic slot, as well as the gas extraction performance of a directional well with multiple slots. The results indicate that (1) The Linxing gas recovery failure may be attributed to unsuccessful hydraulic fracturing based on the history matching analysis of field production; (2) Hydraulic slotting causes gradual compaction of the slot until full closure, and results in a rapid stress drop exceeding 7 MPa in the elliptical zone surrounding the slot, which is the large plastic damage zone; (3) The enhanced permeability in plastic zone exceeds ten times the natural coal permeability, leading to total gas desorption of 556 m3 from elastic and plastic zones; (4) Performance optimization can be achieved through reducing slot length and increasing slot width when using directional well with multiple slots. In summary, this research demonstrates the efficiency of directional wells with multiple slots in enhancing gas recovery from deep coal seams.

A multi-physics coupled multi-scale transport model for CO2 sequestration and enhanced recovery in shale formation with fractal fracture networks

CO2 sequestration and enhanced gas recovery (CS-EGR) of shale formation involve complex multi-physics couplings, which are still not precisely captured by recent models. In this regard, a modified model fully considering the fractal characterization of fracture networks and multi-physics coupled transport behaviors in multi-scale shale formation is established. The fractal fracture networks are depicted based on the L-system theory with microseismic events (MSE), and embedded into the numerical modeling by an automatic fitting algorithm. As a development from the traditional transport model, the formulas among the pressure field, thermal field, and the molecular diffusion of binary gases are constructed based on the Chapman-Enskog theory. The effect of tortuosity and surface diffusion on gas transport efficiency can reach up to 5 %. The morphology parameters of induced fractures affect gas migration mainly by changing the size of SRV and the space between adjacent induced fractures, with their influence on CH4 production potentially as high as 20 %. Meanwhile, there are improved CH4 production, energy efficiency, and CO2 storage amounts, when the injection parameters are optimized. By optimizing the injection conditions (temperature, pressure), CH4 production can be increased by about 8 %.

Insights into in-situ imbibition behavior of fracturing fluid in propped shale fractures based on nuclear magnetic resonance: A case study from Longmaxi Formation shale, Sichuan Basin, China

Shale gas is an important component of unconventional oil and gas resources. Studying the imbibition behavior is helpful to optimize flowback parameters and enhance gas recovery. Recent imbibition studies have focused on shale matrix, and the pressure conditions discussed were mostly atmospheric. The initial imbibition behavior begins from propped fractures to matrix, but there are few studies working on explaining the imbibition behavior in propped fractures or the phenomenon of many shale wells exhibit higher productivity after a “soaking” period. Therefore, propped fracture samples were designed for imbibition and migration experiments. In order to accurately study the mechanism and main influencing factors of fracturing fluid imbibition and migration in propped and unpropped shale fractures under high temperature and high pressure, a series of experiments based on nuclear magnetic resonance (NMR) were carried out. Results showed that NMR T2 spectra of all samples exhibited a bimodal distribution. The final imbibition volume of fracturing fluid was positively related to pressure and fracture width. The imbibition effect of fracturing fluid was more evident in matrix pores under high pressure. In the migration during soaking stage, the fracturing fluid gradually migrated from large pores to small pores and gradually displaced the shale gas from the matrix, thus allowing the water blocking in propped fractures to self-unlock to some extent. Gas permeability decreased in the imbibition stage, while it recovered in the migration stage to some extent.

Enhanced gas recovery: Theory, technology, and prospects

Research on the enhanced gas recovery (EGR) technology is urgently needed in most of China's major gas fields due to low recovery in their late development stages. To promote progress in ERG theory and technology, this paper establishes a unified and universal model for gas recovery evaluation, analyzes the key factors affecting the gas recovery, and expects the prospect of EGR. The results are obtained as follows. First, the production degree of reserves, pressure drawdown sweep efficiency and pressure depletion efficiency are key factors affecting the gas recovery, which is the product of the coefficients corresponding to these factors. Second, according to the development practice of Anyue Longwangmiao gas reservoir, Kela 2 gas field, Sulige gas field and Southern Sichuan shale gas, it is estimated that the recovery of conventional water-driven gas reservoirs and unconventional gas reservoirs (incl. tight gas and shale gas) can be improved by 6–15 percentage points by increasing the production degree of reserves, the pressure drawdown sweep efficiency and pressure depletion efficiency. Third, it is proposed that clarifying the EGR mechanism, developing new EGR methods, and promoting the field test of EGR technologies are directions for theoretical and technical researches. The study results provide a theoretical foundation for EGR. The EGR methodologies for different types of gas reservoirs provide technical support for improving gas recovery and stable production of existing gas fields, promote healthy and rapid development of natural gas industry in China and provide guidance for guaranteeing national energy security.

Numerical simulation of CO2 sequestration in shale gas reservoirs at reservoir scale coupled with enhanced gas recovery

Numerical simulation of CO2 sequestration in shale gas reservoirs at reservoir scale coupled with enhanced gas recovery

EOR technologies for fractured-vuggy carbonate condensate gas reservoirs

There are abundant marine carbonate rock resources in China, which are dominated by fractured-vuggy carbonate oil and gas reservoirs accounting for over two thirds of proved reserves. The fractured-vuggy carbonate condensate gas reservoir in the Tarim Basin is at a burial depth of 4500–7000 m with the characteristics of extremely strong reservoir heterogeneity, complicated and diverse reservoir seepage media, complex fluid properties and quite difficult static characterization, which brings many challenges to reserve evaluation, development plan design and performance analysis. In order to improve the recovery factor of this type of oil and gas reservoir, this paper takes the dynamic characterization to supplement the static characterization and combines each other to improve the accuracy. In addition, based on many years' of dynamic and static research and development practice, the key enhanced gas recovery (EGR) technologies for fractured-vuggy carbonate condensate gas reservoirs are innovatively developed, such as the high-accuracy dynamic characterization technology with dynamic and static iteration for fractured-vuggy body in the strongly attenuated area of desert by taking seismic inversion information as the basis and 3D numerical well test as the core, the multi-target 3D development technology in one well to improve reserve production of fractured-vuggy condensate gas reservoirs, and the gas-lift depressurization EGR technology for fractured-vuggy condensate gas reservoirs. In conclusion, this technological system better solves the key difficulties in the fine characterization of fractured-vuggy body, reserve production improvement and abandonment pressure reduction of well. What's more, it realizes the fine reservoir characterization of fractured zones and feather-shaped fractured zones and the accurate prediction of key development indexes, and increases the deployment success rate of effective wells and efficient wells by 26% compared with that in the initial stage of large-scale productivity construction. To sum up, these technologies provide powerful technical support and reference experience for the scientific and efficient development of fractured-vuggy carbonate condensate gas reservoirs.

Microscopic gas displacement efficiency of enhanced gas recovery in carbonate gas reservoirs with edge and bottom water

Carbonate gas reservoirs with edge and bottom water contain abundant reserves, making them key production targets in the Tarim Basin, Sichuan Basin, Ordos Basin, and other petroleum provinces. Water invasion may occur in the middle and late development stages of such reservoirs, leading to reduction of gas displacement efficiency and gas recovery. In this paper, a pore-scale water-gas immiscible flow model is established by coupling the fluid flow equation and the gas-water contact (GWC) tracking equation. The process of gas displacement with water is simulated in the heterogeneous porous media generated by the quartet structure generation set (QSGS). Finally, the mechanisms of remaining gas distribution and formation are analyzed, and the variation mechanism of microscopic gas displacement efficiency is discussed. The results are obtained in three aspects. First, the remaining gas is distributed at the blind end, in the pore-throat and as clusters, with their proportions and scales jointly controlled by microscopic pore structures, wettability and capillary number. The remaining gas can be further produced by changing the production pressure differential to disturb the original pressure system and gas expansion, so as to improve the microscopic gas displacement efficiency. Second, the microscopic gas displacement efficiency is closely related to the gas flow process. Formation or expansion of each water flow path may cause rapid increase of water cut and slows down the increase of gas displacement efficiency. Third, the microscopic pore structure and wettability are the inherent features of the gas reservoir, so the capillary number can be optimized to change the mode of GWC advancement, and then to effectively improve the microscopic gas displacement efficiency. It is concluded that for real gas wells, the evolution of mechanical mechanisms of GWC advancement should be revealed depending upon the microscopic pore structure and wettability of the reservoir, and then the optimal capillary number can be determined. Furthermore, clarifying the pore-scale water-gas flow characteristics and physical mechanism of microscopic gas displacement provides guidance for the planning of enhanced gas recovery.

CO2 Injection for Enhanced Gas Recovery and Geo-Storage in Complex Tight Sandstone Gas Reservoirs

With the popularization of natural gas and the requirements for environmental protection, the development and utilization of natural gas is particularly important. The status of natural gas in China’s oil and gas exploration and development is constantly improving, and the country is paying more and more attention to the exploitation and utilization of natural gas. The Upper Paleozoic tight sandstone in the Ordos Basin is characterized by low porosity, low permeability and a large area of concealed gas reservoirs. By injecting carbon dioxide into the formation, the recovery rate of natural gas can be improved, and carbon neutrality can be realized by carbon sequestration. Injecting greenhouse gases into gas reservoirs for storage and improving recovery has also become a hot research issue. In order to improve the recovery efficiency of tight sandstone gas reservoirs, this paper takes the complex tight sandstone of the Upper Paleozoic in the Ordos Basin as the research object; through indoor physical simulation experiments, carried out the influence of displacement rate, fracture dip angle, core permeability, core dryness and wetness on CO2 gas displacement efficiency and storage efficiency; and analyzed the influence of different factors on gas displacement efficiency and storage efficiency to improve the recovery and storage efficiency. The research results show that under different conditions, when the injection pore volume is less than 1 PV, the relationship between the CH4 recovery rate and the CO2 injection pore volume is linear, and the tilt angle is 45°. When the injection pore volume exceeds 1 PV, the CH4 recovery rate increases slightly with the increase in displacement speed, the recovery rate of CO2 displacement CH4 is between 87–97% and the CO2 breakthrough time is 0.7 PV–0.9 PV. In low-permeability and low-speed displacement cores, the diffusion of carbon dioxide molecules is more significant. The lower the displacement speed is, the earlier the breakthrough time is, and the final recovery of CH4 slightly decreases. Gravity has a great impact on carbon sequestration and enhanced recovery. The breakthrough of high injection and low recovery is earlier, and the recovery of CH4 is about 3.3% lower than that of low injection and high recovery. The bound water causes the displacement phase CO2 to be partially dissolved in the formation water, and the breakthrough lags about 0.1 PV. Ultimately, the CH4 recovery factor and CO2 storage rate are higher than those of dry-core displacement. The research results provide theoretical data support for CO2 injection to improve recovery and storage efficiency in complex tight sandstone gas reservoirs.

3D geological modeling of deep fractured low porosity sandstone gas reservoir in the Kuqa Depression, Tarim Basin

The fractured reservoir is one of the significant petroleum reservoir types in China, representing over one-third of total reserves. The Kuqa Depression in the Tarim Basin is dominated by fractured low-porosity sandstone gas reservoirs with characteristic tight matrix, developed fractures, and edge and bottom water. However, the continued development of these reservoirs has led to various problems, including strong reservoir heterogeneity, low well control, complex gas-water relationships, and early water invasion. Addressing these issues requires a detailed understanding of the reservoir’s geological characteristics. One method for achieving a fine reservoir description is through the use of 3D geological modeling. This high-level, comprehensive characterization technique is widely used throughout the entire life cycle of oil and gas field development. A 3D geological model can accurately predict the actual underground reservoir characteristics and provide a geological basis for later numerical simulation work. Based on a study of the geological characteristics of the Kuqa Depression in the Tarim Basin, a 3D geological modeling technique was developed, which includes structural modeling, facies modeling, petrophysical modeling, and fracture modeling. This technology has been successfully applied to many deep gas reservoirs in the Kuqa Depression of the Tarim Basin, leading to enhanced gas recovery.

The influence of irreducible water for enhancing CH4 recovery in combination of CO2 storage with CO2 injection in gas reservoirs

CO2 flooding to enhance gas recovery (CO2-EGR) with CO2 storage offers the prospects of significant environmental and economic benefits by increasing CH4 recovery while simultaneously storing CO2. Most studies ignored the interaction of water with CO2 and the formation rocks and the influence of irreducible water to enhance CH4 recovery combined with CO2 storage were poorly understood by core-flooding experiments. In this research, a numerical model of a five-spot well pattern was developed by benchmarking against the existing literature, and the model was further modified to investigate the effects of irreducible water on CO2-EGR and CO2 storage in gas reservoirs. The injected CO2 preferentially moved horizontally and gradually flowed vertically to flood CH4, making the displacement front an inclined CO2-CH4 mixing zone. The model with irreducible water changed from 0% to 40%, the CO2 sweep efficiency improved and the CH4 recovery increased by 4.37%. This could be attributed to the narrowing of the CO2-CH4 mixing zone and the change in displacement front from an inclined horizontal plane to a near arc plane with better stability. The cumulatively stored CO2 decreased by 21.24%, due to the early CO2 breakthrough and shut-in times. However, because more CO2 was dissolved in water and trapped in residual gas, the contribution of CO2 solubility trapping and CO2 residual trapping increased by 12.01% and 10.34% respectively, while CO2 structural trapping decreased by 22.86%, resulting in a significant increase in long-term storage security. Mineral reactions had a negligible influence on CO2-EGR and CO2 sequestration in the CO2 flooding process. The higher the salinity, the lower the amount of dissolved CO2, and the lower the CH4 recovery and cumulatively stored CO2, with decreased security of CO2 storage with limited impact. The higher the irreducible water saturation (Swi), the more CO2 dissolved, and the CH4 recovery and long-term storage security of CO2 improved with a reduction of cumulatively stored CO2. Changing the gas relative permeability (Krg) has a small effect for CH4 recovery and CO2 storage. This research may provide new insights into analyzing the mechanism of irreducible water on the influence of CO2-EGR and CO2 storage, laying a foundation for the optimization of CO2-EGR schemes and the implementation of field applications in water-bearing gas reservoirs with CO2 injection in the future.

New Insight into Enhancing Organic-Rich Shale Gas Recovery: Shut-in Performance Increased through Oxidative Fluids

Oxidizing stimulation of organic-rich shale reservoirs, as a supplement of hydraulic fracturing, was proposed to enhance shale gas recovery. Previous publications revealed that the interaction between organic-rich shale and oxidative fluids causes the components’ dissolution, which induces lots of pores and microfractures, resulting in rock microfracturing without confined pressure and associated increments of the matrix permeability, and improving unpropped fracture conductivity. However, the enhancement of shale gas recovery with oxidative fluids still lacks an implementation clue targeted for specific engineering problems. In recent years, water–rock interaction inducing microfractures indicates a positive effect of retained fracturing fluid on the stimulation after the fracturing operation, which sheds light in the enhancement of shale gas production by shut-in. The objectives of this study are to provide a new perspective whereby the shut-in performance to enhance shale gas recovery could be increased by the injection of oxidative fluids into the formation during the fracturing operation. Firstly, the mechanisms of shut-in performance increased by oxidative dissolution, which illustrate the increment of the density of fracture networks, the improvement of fracture network conductivity, and the promotion of gas desorption and diffusivity, are demonstrated. Then, the feasibility of using oxidative fluids to increase shut-in performance, which follows the geological and engineering characteristics of organic-rich shale reservoirs, is evaluated. Finally, according to the analysis of production performance for two typical types of shale gas wells, in which one is a low gas production and a high fracturing fluid recovery (LGP-HFR) and the other is a high gas production and a low fracturing fluid recovery (HGP-LFR), a shut-in strategy with oxidative fluids to enhance shale gas recovery is developed. This indicates that the injection of oxidative fluids during the fracturing operation may become a promising and cost-effective approach to enhance shale gas recovery.