CO2 Injection Pressure Research Articles

Investigation into Enhancing Methane Recovery and Sequestration Mechanism in Deep Coal Seams by CO2 Injection

Injecting CO2 into coal seams to enhance coal bed methane (ECBM) recovery has been identified as a viable method for increasing methane extraction. This process also has significant potential for sequestering large volumes of CO2, thereby reducing the concentration of greenhouse gases in the atmosphere. However, for deep coal seams where formation pressure is relatively high, there is limited research on CO2 injection into systems with higher methane adsorption equilibrium pressure. Existing studies, mostly confined to the low-pressure stage, fail to effectively reveal the impact of factors such as temperature, high-pressure CO2 injection, and coal types on enhancing the recovery and sequestration of CO2-displaced methane. Thus, this study aims to investigate the influence of temperature, pressure, and coal types on ECBM recovery and CO2 sequestration in deep coal seams. A series of CO2 core flooding tests were conducted on various coal cores, with CO2 injection pressures ranging from 8 to 18 MPa. The CO2 and methane adsorption rates, as well as methane displacement efficiency, were calculated and recorded to facilitate result interpretation. Based on the results of these physical experiments, numerical simulation was conducted to study multi-component competitive adsorption, desorption, and seepage flow under high temperature and high pressure in a deep coal seam’s horizontal well. Finally, the optimization of the total injection amount (0.7 PV) and injection pressure (approximately 15.0 MPa) was carried out for the plan of CO2 displacement of methane in a single well in the later stage.

Effect of CO2 injection pressure on enhanced coal seam gas extraction

The CO2 displacement of coal seam gas can simultaneously promote gas extraction and CO2 sequestration, with gas injection pressure being a key factor influencing both efficiency and safety. This study examined the impact of varying CO2 injection pressure on gas extraction and sequestration. The findings indicated that higher CO2 injection pressures reduced the gas injection and extraction time costs, increased the equilibrium pressure and coal seam temperature, and decreased carbon sequestration efficiency. As the CO2 injection pressure increased, the CH4 cumulative desorption capacity and desorption rate rose by 4.98%, the time to reach the residual gas content critical value (TLV of 2 m3/t) shortened by 62.04 min, and the maximum CO2 storage per unit mass of coal increases by 3.6 m3/t. Increasing the injection pressure enhanced gas desorption and CO2 sequestration. A higher CO2 injection pressure resulted in a higher CH4 yield rate and a reduced CO2 injection rate in the later stages. Therefore, it is advisable to reduce the CO2 injection pressure during the low efficiency desorption stage.

Investigation on the impact of CO2-Induced precipitation on microscopic pore structure of low-permeable reservoirs

CO2 injection into reservoirs might induce organic or inorganic precipitation in microscopic pores, and some of the pores are blocked by the precipitates, resulting in a decrease in the connectivity of pores and affecting oil recovery. In this paper, a set of experiments on CO2 displacement and CO2-water-oil-rock interaction are conducted to study the microscopic mechanisms of reservoir damage. In-situ Nuclear Magnetic Resonance (NMR) technology is applied to conduct the microscopic analysis of CO2-EOR and reservoir damage at real reservoir conditions. The results reveal that the particle size and the amount of inorganic precipitates formed in the formation water will increase with the rise of CO2 injection pressure, and the inorganic precipitates primarily consist of siderite and kaolinite. The change of NMR T2 spectra of the core samples reveals that the inorganic precipitates primarily block the small pores less than 0.89 μm. However, as a result of stronger mineral dissolution and solute transport, the pore volume of the large pores (greater than 0.89 μm) increases after the CO2-water-rock reaction. Ultimately, this interaction results in a 5.4% increment in pore volume. In addition, the displacement efficiency of water-saturated cores is improved after the first CO2 displacement, which indicates that CO2-water-rock interaction can effectively improve the seepage properties of reservoirs. Nevertheless, the reservoir damage caused by asphaltene precipitation during CO2 flooding is more significant. The asphaltene precipitation percentage in formation oil increases with the rise of CO2 injection pressure, reservoir temperature, and asphaltene content in virgin oil. CO2-induced asphaltene precipitation causes more severe blockage on small pores in comparison with large pores. After 2 h of CO2 injection to the oil-saturated core, permeability and oil recovery caused by CO2-induced precipitation decreased by 17.6% and 11.4%, respectively.

Carbonation mechanism and cementation properties of recycled cement paste based on CO2 injection time and pressure

Current applications of recycled cement paste (RCP) carbonation mainly focus on using carbonized particles as filler materials or enhancing the adhesion of hardened cement paste to aggregates. However, there is limited research on the carbon dioxide (CO2) sequestration effectiveness and strength improvement mechanisms of carbonized waste recycled concrete powder as a cementitious material. This study investigates the carbonation mechanism and cementation properties of RCP under various carbonation conditions. The phase composition and microstructural evolution of RCP are systematically analyzed through detailed characterization tests, exploring the impact of carbonation time and CO2 pressure on the mechanical properties of the RCP samples. These findings demonstrate that prolonged carbonation enhances the formation of calcium carbonate (CaCO3) and crystalline silica (SiO2), which in turn improves particle bonding and reduces porosity. Higher CO2 pressure results in increased carbonation products and tighter interparticle binding. Advanced nuclear magnetic resonance (NMR) analyses indicate that carbonation facilitates the transition of Al from six- to four-coordinated states and the polymerization of SiO4 tetrahedra, leading to enhanced structural cohesion. This study demonstrates the potential of carbonation in reshaping the cementitious properties of RCP, highlighting its environmental and economic benefits for recycling construction waste.

Molecular simulation of free CO2 injection on the coal containing CH4 structure and gas replacement

Understanding the replacement process of pre-adsorbed CH4 by injecting CO2 into the coal slit pores is crucial for CO2 storage and coalbed methane (CBM) extraction. We constructed the model of free CO2 injection into coal containing CH4, and used molecular simulation methods to analyze the replacement and diffusion of gas in coal as well as the coal structure deformation at different CO2 injection pressures. Results indicated that the CO2 adsorption following injection aligned with Langmuir law, and CO2 replaced CH4 more efficiently at 6 MPa injection pressure; After CO2 injection, the coal slit pore volume increased, the coal matrix aromatic structure destroyed, the coal matrix micropores volume increased and expanded radially and compressed longitudinally. Among them, the coal matrix deformation facilitated CO2 adsorption whilelittle impacting the CH4 desorption within the micropores. Higher CO2 injection pressure reduced the diffusion coefficients of adsorbed and free CH4 and CO2, but increased the CO2 adsorption depth in the coal matrix and enhanced the CO2 adsorption stability. The results provided valuable insights into the potential mechanisms of CO2-ECBM.

A novel interdisciplinary model for optimizing coalbed methane recovery and carbon dioxide sequestration: Fracture dynamics, gas mechanics, and its application

The Carbon Dioxide Enhanced Coalbed Methane (CO2-ECBM) technique significantly enhances clean energy extraction and mitigates climate change. Central to this process is the dynamic evolution of rough fracture networks within coal seams, influencing the migration of CO2 and natural gas. However, existing research lacks a comprehensive, quantitative approach to examining the micro-evolution of these fractures, including fracture roughness, fracture density, fracture touristy, and fracture size, particularly under thermo-hydro-mechanical effects. Addressing this gap, our study introduces an innovative, fractal model for quantitative analysis. This model intricately characterizes fracture networks in terms of number, tortuosity, length, and roughness, integrating them with fluid dynamics affected by external disturbances in CO2-ECBM projects. Upon rigorous validation, the finite element method analysis reveals significant impacts of micro-parameters on permeability and natural gas extraction. For instance, increasing CO2 injection pressure from 4 to 6 MPa changes fracture network density by up to 6.4%. A decrease in fracture density (Df) from 1.6 to 1.5 raises residual gas pressure by 2.7% and coal seam stress by 9.5%, indicating crucial considerations for project stability. Applying the proposed interdisciplinary model to assess CO2 emissions in Australia, it is can be obtained that when Df decreases from 1.6 to 1.5, the total amount of CO2 storage reduces by 17.71%–18.04%. Our results demonstrate the substantial influence of micro-fracture behaviors on CO2-ECBM projects, offering a ground-breaking solution for efficient greenhouse gas reduction and clean energy extraction, with practical implications for the energy sector's sustainability.

Triaxial-mechanical and permeability properties of coal body under varying CO2 pressures

The sequestration of CO2 in coal seams has become an effective way to curb greenhouse-gas emissions. Coal mechanics and permeability properties are key factors affecting the safe sequestration of CO2 in coal seams, and both are significantly affected by the CO2 injection pressure. In this study, triaxial compression-permeability tests were conducted on coal under varying CO2 and limited confining pressures using a measurement system to determine the coupled mechanical properties and adsorption permeability of coal. The effects of CO2 pressure on the mechanical properties and evolution of coal permeability were investigated. A three-dimensional statistical damage constitutive model of coal that considers CO2 adsorption damage was established. The results showed that the stress–strain curve of the coal was divided into four stages. During the first two stages, the amplitudes of the permeability changes were small, whereas at the peak stress point, a permeability “jump” phenomenon occurred, after which an increase in stress resulted in a slower amplitude increase in permeability. The CO2 pressure had an evident damage-deterioration effect on the mechanical properties of the coal samples, and the primary failure characteristic was shearing damage. The higher the CO2 pressure, the higher the degree of internal fragmentation and fracture network complexity of the coal body. During the triaxial compression-permeability experiment, the normalized permeability of the coal samples tended to increase slowly, followed by a rapid increase and back to a slow increase. However, with increasing CO2 pressure, the initial permeability of the coal samples decreased, whereas the normalized permeability increased sharply. The rationality and accuracy of the constitutive model were verified by comparing the established constitutive model and test stress–strain curves of the coal samples. The results of this study can provide theoretical references for CO2 geological storage and facilitate the selection of appropriate CO2 injection pressures.

Effect of CO2-H2O Interaction with High-Rank Coal on Mechanical Properties and Acoustic Emission Characteristics under Confining Pressure.

The adsorption of CO2 by coal leads to changes in its mechanical properties, particularly when considering supercritical CO2 and water with supercritical CO2 adsorption. This is strongly linked to the efficiency of CO2-enhanced coalbed methane (CO2-ECBM) extraction and the safety of CO2 geological storage. This study focuses on 3# coal from the Datong Mine in Gaoping City, Shanxi Province. The high-rank coal's mechanical properties, including the triaxial compressive strength and elastic modulus, were examined under the combined effects of CO2 injection pressure, CO2 injection time, and moisture content. The triaxial compressive strength and elastic modulus of the coal showed a decrease following CO2 injection. Increasing the CO2 injection pressure, prolonging the CO2 injection time, and increasing the moisture content were favorable for coal softening. In particular, the triaxial compressive strength and elastic modulus of the coal sample after 144 h of water and supercritical CO2 softening decreased by 67.67 and 64.15%, respectively. Injecting CO2 into coal changed its failure mode. The dry raw coal sample exhibited a brittle shear failure mode, while the coal samples showed transitional shear failure after injecting 6 MPa CO2 and 8 MPa CO2 and ductile nondilatant barreling failure after injecting water and 8 MPa CO2 (with a moisture content of 3.02%). Moreover, the cumulative acoustic emission energy of the coal samples followed a similar trend to the decrease in mechanical properties under different conditions. The physical and chemical interactions among coal, CO2, and water caused the softening of coal; these included the generation of the swelling stress, the dissolution of minerals by carbonate solutions, the reduction in surface energy of coal owing to CO2 adsorption, and the extraction and plasticization reactions of organic matter in coal. The research results are of great significance for further understanding CO2-ECBM and CO2 geological sequestration.

Thermomechanical coupling seepage in fractured shale under stimulation of supercritical carbon dioxide

As a waterless fracturing fluids for gas shale stimulation with low viscosity and strong diffusibility, supercritical CO2 is promising than the water by avoiding the clay hydration expansion and reducing reservoir damage. The permeability evolution influenced by the changes of the temperature and stress is the key to gas extraction in deep buried shale reservoirs. Thus, the study focuses on the coupling influence of effective stress, temperature, and CO2 adsorption expansion effects on the seepage characteristics of Silurian Longmaxi shale fractured by supercritical CO2. The results show that when the gas pressure is 1–3 MPa, the permeability decreases significantly with the increase in gas pressure, and the Klinkenberg effects plays a predominant role at this stage. When the gas pressure is 3–5 MPa, the permeability increases with the increase in gas pressure, and the influence of effective stress on permeability is dominant. The permeability decreases exponentially with the increase in effective stress. The permeability of shale after the adsorption of CO2 gas is significantly lower than that of before adsorption; the permeability decreases with the increase in temperature at 305.15 K–321.15 K, and with the increase in temperature, the permeability sensitivity to the temperature decreases. The permeability is closely related to supercritical CO2 injection pressure and volume stress; when the injection pressure of supercritical CO2 is constant, the permeability decreases with the increase in volume stress. The results can be used for the dynamic prediction of reservoir permeability and gas extraction in CO2-enhanced shale gas development.

A Study on the Plugging Effect of Different Plugging Agent Combinations during CO2 Flooding in Heterogeneous Reservoirs

Gas channeling control is key to improving CO2-flooding efficiency. A traditional plugging system has disadvantages, such as poor adaptability and stability, leading to the poor plugging effect of CO2 channeling in heterogeneous reservoirs and difficulty in controlling the subsequent CO2 injection pressure. To achieve a significant plugging effect and effectively control the subsequent CO2 injection pressure, a heterogeneous physical model of gas channeling in a horizontal well was established, and plugging experiments were conducted using four different combinations of plugging agents during CO2 flooding. Three evaluation parameters were defined, including the temperature field variation coefficient (TFVC), medium-permeability diversion rate (MPDR), and subsequent injection pressure coefficient (SIPC). The plugging effect of different combinations of plugging agents during CO2 flooding in heterogeneous reservoirs was analyzed. The results show that the plugging effect after using a combination of plugging agents was significantly better than after using a single plugging agent, and different plugging agent combinations had distinct characteristics. The strong–medium–weak (S-M-W) combination had the best MPDR for subsequent CO2 flooding, but the SIPC was the highest. The strong–weak–strong–weak (S-W-S-W) and weak–strong–weak–strong (W-S-W-S) combinations could effectively control the SIPC. These results indicate that plugging using the S-W-S-W and W-S-W-S combinations can achieve an effective plugging effect and reasonably control the subsequent CO2 injection pressure. This work provides a personalized design scheme for effective gas channeling control and maintenance of appropriate injection pressure during CO2 flooding in heterogeneous reservoirs.

The Response Characteristics of Pore Volume and Specific Surface Area of Different Phases of Carbon Dioxide Injection into Anthracite Coal Pores

After the coal sample reacts with CO2, the porosity and pore volume change. Compared with dry raw coal sample, the porosity of coal after CO2 adsorption is increased. With the increase of CO2 injection pressure, the porosity of coal will gradually increase, especially when CO2 enters the supercritical phase. In terms of pore capacity of coal samples, CO2 adsorption time, CO2 adsorption pressure and CO2-H2O treatment do not show obvious regularity in the changes of pore capacity of coal samples, but in general, the increase of CO2 adsorption pressure and CO2-H2O treatment have a positive effect on the increase of pore capacity of coal samples, especially ScCO2-H2O. The mesoporous pore capacity increased by 137.1%. In terms of macro pore volume of coal sample, the change of macro pore volume after CO2 adsorption is more regular. Extending CO2 adsorption time, increasing CO2 adsorption pressure and CO2-H2O treatment all have positive effects on the increase of macro pore volume of coal sample. Under 8MPaScCO2-H2O, macro pore volume reaches a maximum of 0.016462ml/g. The increase also reached 130.4 percent. On the mesoporous specific surface area of coal sample, increasing CO2 adsorption pressure, prolongating CO2 adsorption time and CO2-H2O treatment can increase the mesoporous specific surface area of the sample. The mesoporous specific surface area of the sample at 8 MPa ScCO2-H2O is 0.631 m2/g, which reaches the maximum in this experiment, with an increase of 334.27%.

Investigating Asphaltene Precipitation and Deposition in Ultra-Low Permeability Reservoirs during CO2-Enhanced Oil Recovery

CO2 flooding is an economically feasible and preferred carbon capture, storage, and utilization technology. Asphaltene deposition is a common problem in the process of CO2 injection because it may cause reservoir damage. The mechanism of asphaltene precipitation damage to the formation remains elusive. Experiments were conducted to reveal the pore-scale formation damage mechanism in ultra-low permeability reservoirs caused by asphaltene precipitation during CO2 flooding. Initially, the precipitation onset point for asphaltene within the crude oil-CO2 system was determined using a high-pressure tank equipped with visual capabilities. Subsequently, CO2 flooding experiments were conducted on ultra-low permeability cores under miscible and immiscible conditions, with the support of nuclear magnetic resonance (NMR) to quantitatively evaluate the impact of asphaltene precipitation on ultra-low permeability reservoirs. The results indicate that within the pressure range from the asphaltene precipitation onset point to the minimum miscibility pressure (MMP). The level of asphaltene precipitation rises as CO2 injection pressure increases. In the miscible flooding stage, asphaltene precipitation can still occur, but to a lesser extent. Notably, asphaltene deposition predominantly occurs in larger pores; above the MMP, the permeability decreases significantly as asphalt particles agglomerate, resulting in notable pore-throat blockages. While asphaltene deposition has a minimal impact on porosity, the bridging effect of asphaltene particles reduces permeability.

Study on the Influencing Factors of Injection Blockage during CO2 Sequestration in One-Dimensional Long Reactor

Carbon sequestration through CO2 injection into a formation is an effective strategy for reducing greenhouse gas emissions. In this study, a one-dimensional long reactor was constructed to simulate the CO2 injection process under various sediment temperatures, pressures, and flow rates. The formation of CO2 hydrate and the resulting blockages were investigated in detail through a series of indoor experiments. Due to the increasing driving force for CO2 hydrate formation, reducing sediment temperature and increasing sediment pressure can cause hydrate blockage to form near the injection end, leading to an increase in CO2 injection pressure and a reduction in the storage range. Furthermore, CO2 injection rate has a substantial impact on the pattern of hydrate blockage. A lower injection rate facilitates full contact between CO2 gas and pore water, which helps to increase the formation and blockage degree of CO2 hydrates, thereby decreasing the amount of CO2 injection. The experimental investigation presented in this paper examines the laws of CO2 injection and clogging under various sediment conditions and injection processes on a one-dimensional scale, which can provide valuable insights for the design of CO2 sequestration processes.

Shear Wave Velocity Applications in Geomechanics with Focus on Risk Assessment in Carbon Capture and Storage Projects

Shear wave velocity (Vs) has significant applications in geoengineering investigations. With the ongoing rise in carbon capture and storage (CCS) initiatives, the role of Vs in monitoring the CO2 sequestration sites is escalating. Although many studies have been conducted to assess CCS-induced risks, no inclusive research has been conducted integrating those investigations. This study strives to collate and integrate the applications of Vs in geoscience with an emphasis on CCS risk assessment. Based on this research, major CCS-induced risks were detected: induced seismicity, caprock failure, groundwater contamination, fault reactivation, and reservoir deformation. These risks were inclusively described, and the mathematical formulations incorporating the Vs parameter in risk analysis were elaborated. It was concluded that Vs applications can be further extended in monitoring CO2 plume migration, optimizing CO2 injection pressures, preventing shallow water contamination, and predicting CCS-induced seismic events. All these applications require fully coupled hydromechanical analysis based on poroelasticity theory. Hence, various factors including pore pressure, in situ stresses, faults distribution, and poroelastic parameters must be carefully determined before the CO2 injection phase. The mathematical formulations presented in the present study are quite applicable for granting the safety and long-term success of subsurface carbon sequestration.

Decoding wettability in coal-water-CO2 system for enhanced sequestration security

The injection of CO2 into deep unminable coal seam is a most promising carbon storage method that can simultaneously achieve the dual objectives of mitigating CO2 emission and enhancing coalbed methane recovery. In this context, the wettability of the coal-water-CO2 system plays an important role in the CO2 injection rate, storage capacity, and sequestration security. However, the factors affecting wettability alternation in the coal-water-CO2 system are still unclear until now. In this study, the sessile drop method was used to measure the contact angle (CA) in the coal-water-CO2 system under different pressures (3 – 8 MPa) and temperatures of (40–70 °C) with four different rank coals. Results indicate that with increasing pressure, the CA shows a steady increase below 5 MPa followed by a rapid increase at 5 – 8 MPa. The CA decreases with increasing temperature and coal rank. The CA is negatively correlated with the mes- and macro-pores, but positively correlated with micropores. It was found that these relationships are attributed to the CO2 density and CO2 adsorption capacity of coal. As the CO2 density increases, the coal-CO2 interaction force intensifies, leading to a tendency towards CO2 wetting for the coal-water-CO2 system. The adsorption capacity illustrates the strength of the coal-CO2 interaction, where the affinity of polar adsorption sites for CO2 molecules exceeds that of nonpolar adsorption sites. Finally, we conducted a comprehensive assessment of the wettability of the coal-water-CO2 system as it varies with burial depth by developing an integrated model that considers four influential factors, including pressure, temperature, coal rank, and pore structure. The findings of this study can be utilized to determine the optimal CO2 injection pressure in CO2-ECBM projects and enhance sequestration safety.

Risk analysis and production safety design of supercritical carbon dioxide storage in gasification combustion cavity

The storage of supercritical carbon dioxide in the coal underground gasification combustion cavity can not only reduce greenhouse gas emissions, help control global climate change, but also avoid potential geological hazards caused by the long-term existence of coal-burning holes. It is an important innovative development direction for the global coal industry. However, currently, there is insufficient examination of the practicality and hazards of UCG-CCS through industrial trials, which considerably restricts the spread and use of UCG-CCS. This study employs theoretical analysis and numerical simulation to examine the geological feasibility of UCG-CCS. It finds that the risk of carbon dioxide leakage in UCG-CCS is predominantly due to overlying rock fractures being diffused by the integrity of the cover layer and the parameters of the gasification furnace. It has also been found that the development height of cap rock fractures is closely related to CO2 injection pressure and gasification furnace width. As CO2 injection pressure increases, the capping fracture exhibits a descending trend resembling a stair-step; as gasification furnace width decreases, the development height of cap rock fractures decreases. On this basis, the technical approach and design method of preventing carbon dioxide leakage in UCG-CCS are proposed. The research findings have significant theoretical and practical implications for site selection and risk assessment in UCG-CCS process engineering.

Machine Learning Provides Fracture Analysis, Mapping for CCUS

_ This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 214996, “Machine-Learning Application for CCUS Carbon Storage: Fracture Analysis and Mapping in the Illinois Basin,” by Guoxiang Liu, SPE, US Department of Energy, and Abhash Kumar and William Harbert, SPE, Contractors, et al. The paper has not been peer reviewed. _ The monitoring of storage reservoirs to ensure safe, long-term storage of CO2 and to derisk operations and storage management is undergoing dynamic shifts, expanding opportunities for implementing innovative techniques and applications, especially for commercial-scale deployment. In the complete paper, a method with multitiered analysis has been developed to leverage advanced machine-learning (ML) techniques to process passive seismic monitoring data acquired during an injection period along with pumping/injection pressure and rate in the Illinois Basin for potential fracture and fault analysis. Introduction This study is part of the Science-Informed ML for Accelerating Real-Time Decisions in Subsurface Applications (SMART) Initiative funded by the US Department of Energy Carbon Storage Program. The outcomes of the SMART Initiative are science-informed, ML-based tools that can be applied at carbon storage sites throughout the nation and the world to achieve the following objectives: - Improve the ability to consolidate technical knowledge, site-specific characterization information, and real-time data in a digestible way - Enable the optimization of carbon-storage reservoirs by creating a capability for real-time forecasting of the behavior of such reservoirs - Improve the ability to understand and communicate subsurface behavior during carbon-storage operations to nonexperts Methodology In the authors’ study, a multitiered, data-driven approach was created by integrating all available measurement data to visualize fracture networks. The data sets included measurements from drilling, log and core testing, injection and downhole pressure measurements, and five vertical-pressure-monitoring gauges, providing a wealth of detail on the fracture networks. A fracture network encompasses natural fractures, induced or hydraulic fractures, and the dynamic response of such fractures, culminating in a comprehensive understanding of this system. Because of the wide range of resolutions and scales of the data sets, the fracture network was mapped into 19 distinct time windows over a 3-year injection period by analyzing pumping data, which included CO2 injection and bottomhole pressure. Passive seismic data (microseismic) were compartmentalized into these time windows, similar to the industry practice of compartmentalizing microseismic data into separate stages for high-pressure fluid- injection activities (i.e., induced fracturing). In each of these time windows, the b-value of the associated microseismic population was estimated. Furthermore, event-occurrence time and distance from the treatment well were used to identify the distinct triggering front of microseismicity likely associated with pre-existing fractures and faults within the reservoir. Seismogenic b-value and diffusivity analyses were applied to identify triggered fronts for further clustering and fracture-plane and 3D fracture-distribution analysis. The potential of several unsupervised ML algorithms was leveraged to identify the spatial clusters of microseismic events within each triggering front of individual time windows by following the work flow described in Fig. 1 of the complete paper. Furthermore, these ML techniques were implemented to determine the best-fitting surface for each spatial cluster of microseismicity to infer the directional and spatial distributions of fractures.

Effects of CO2 injection pressure and confining pressure on CO2-enhanced coalbed methane recovery: Experimental observations at various simulated geological conditions

Systematic understanding of the characteristics of fluid transport and occurrence in conventional Coalbed Methane (CBM) recovery and Injecting CO2 enhancing CBM recovery (CO2-ECBM) engineering plays an essential role in improving the recovery rate of CBM and mitigating the greenhouse effect. In this study, the displacement adsorption time, fluid flow rate and cumulative fluid flow rate of different coal rank samples under conventional and CO2 injection conditions were obtained. The efficiency of exchange adsorption was evaluated based on sweep efficiency and displaced volume. It is found that: (a) In conventional CBM recovery, there is no good correlation between the CBM recovery amount and the gas adsorption capacity of different coal rank samples, but CO2 injection can effectively improve the CBM recovery amount of coal reservoir. (b) In CO2-ECBM, the overall flow rate of the mixed gas decreases rapidly in the initial stage, and then when CO2 is detected at the end, the flow rate of the mixed gas gradually increases and becomes stable until the displacement is completed. (c) Due to the fluid velocity sensitivity effect of coal reservoirs, excessive CO2 injection pressure will have a negative effect on sweep efficiency, but confining pressure will weaken this negative effect. (d) Confining pressure changes the pore-fracture structure of coal reservoirs, strongly influencing conventional CBM recovery. However, it does not change the gas occurrence mechanism in the coal reservoir, it only causes a larger number of gas molecules in the coal matrix instead of the pores, which has little influence on the effectiveness parameters of CO2-ECBM. This research is of great significance for the systematic understanding of the occurrence mechanism of multiple fluids in coal reservoirs, the safe and efficient development of CBM resources, and the realization of carbon neutrality.

Effect of CO2 injection on the gas desorption and diffusion kinetics: An experimental study

During CO2 displacement, the diffusion characteristics of gas in the coal matrix are among the key factors that affect the gas extraction rate, and discussed the influence mechanism of CO2 injection on the diffusion kinetics of coal seam gas. In this study, we used a self-developed CO2–CH4 displacement experimental platform to study the diffusion characteristics of CH4 under different CO2 injection pressures and temperatures. As the CO2 injection pressure was increased from 0.6 MPa to 1.0 MPa, the CH4 production increased by 9.44 %, the CH4 maximum diffusivity increased by 0.05, the effective diffusion coefficient extreme point increased by 111.45 %. As the gas injection temperature was increased from 40 °C to 60 °C, the CH4 production increased by 4.02 %, the CH4 maximum diffusivity increased by 0.03, the maximum of the effective diffusion coefficient increased by 103.31 %. To better explain the gas diffusion characteristics during CO2 displacement, the influence mechanism of increasing CO2 injection pressure and temperature on the CH4 diffusion kinetics was discussed, and the driving force (fd) and resistance (fr) during the displacement process were studied. The dynamic CO2 injection models were considered to be more effective in ensuring efficient CH4 recovery.

The impacts of CO2 flooding on crude oil stability and recovery performance

Numerous studies have investigated the fundamental mechanisms by which CO2 flooding can increase oil production by altering the properties of the hydrocarbon fluid, including oil swelling, viscosity and interfacial tension reductions, and the extraction of light-to-intermediate components. However, the interactions between CO2 and hydrocarbon fluid may also cause several problems, such as asphaltene precipitation due to crude oil's instability during the CO2 flooding process. This study investigates the complex factors that affect the instability of crude oil, including CO2 injection pressures, temperatures, and crude oil compositions. The light-dead oil samples taken from two Indonesian oil fields were used. The impacts of the instability of crude oil on CO2 displacement performance were also observed to evaluate oil recovery and minimum miscibility pressure (MMP). The observation was performed using a slim tube under varying CO2 high-pressure injections at 90 °C and 70 °C. The produced oils were analyzed based on their polarity component, saturates, aromatics, resins, and asphaltenes fractions, to observe the changes in oil composition and colloidal index instability. The results showed that increasing temperatures at given pressures resulted in higher oil recovery. Moreover, the asphaltene and resin fractions in the oil produced at a lower temperature significantly decrease compared to those at a higher temperature. It was also shown that asphaltene tends to precipitate more easily at a lower temperature. The other phenomenon revealed that the lighter oil resulted in a lower recovery than the heavier oil at a given pressure and temperature and correspondingly higher MMP. It was also suggested that CO2 flooding is more likely to cause asphaltene precipitation in light oils.