With the deepening of coalbed methane (CBM) exploration and development, the problem of low gas production has gradually become one of the main factors restricting the development of the CBM industry in China. Reasonable well pattern deployment can improve the productivity of CBM wells and reduce the cost of production, while the reservoir changes of CBM wells play a important role for well pattern infilling. In this study, the dynamic characteristics of the average reservoir pressure (ARP), permeability, and drainage radius during the development process of CBM wells are systematically analyzed, and predicted the production changes of well groups before and after infilling wells in combination with the characteristics of reservoir changes. The results show that the high gas production wells have a larger pressure drop, long drainage radius, and a large increase in permeability. On the contrary, low gas production wells are characterized by small drainage radius, damaged permeability and difficult to recover. The productivity of infilled horizontal wells is predicted for two well groups with different productivity and reservoir dynamic characteristics. After infilling wells, the production of current wells has increased at different degrees. It is predicted that the average gas production of low gas production well group H1 and middle gas production well group H2 will increase 1.64 and 2.09 times respectively after 3000 days production simulation. In addition, the pressure interference between wells has increased significantly, and the overall gas production of the well group has greatly increased. Infill wells can achieve better development results in areas with superior CBM resources, recoverable reservoir permeability, and small drainage radius during the early production process. The research results provide a reference for the later infill adjustment of CBM well patterns in the study area.

The Daning-Jixian block, the eastern edge of the Ordos Basin, is one of the most potential areas for CO₂ geological storage, enhanced coalbed methane recovery (ECBM) exploration and production in China in recent decades. The ionic composition and total dissolved solids (TDS) of the produced water, coal organic matter maturity, molecular composition and carbon isotope characteristics of the produced gas were utilized to analyze the hydrogeological condition, CBM generation and migration characteristics in this area. The CBM enrichment patterns and the geological impacts on gas well production characteristics were revealed. The optimal area for CBM development and CO₂ geological storage in the study area were also proposed. Dominated by the Xueguan reverse fault zone, the hydraulic unit in this area can be divided into two parts (i.e., the recharge-runoff zone in the east and the weak runoff-stagnation zone in the west). The thermogenic gas is dominating CBM genesis in this area. Secondary biogenic gas replenishment is only distributed in the eastern margin area, where the δ¹³C₁ value is less than the thermal simulation results as an influence of hydrodynamic fractionation. Finally, two models of CBM formation and accumulation were proposed, 1) thermogenic CBM migrated by hydrodynamic and resorbed for preservation at impermeable fault boundaries; 2) thermogenic CBM trapped by fault and accumulated by hydrodynamic in slope zone. The gas production performance, generally increased from east to west, is mainly dominated by hydrogeological conditions. Generally, the west side of the fault zone is the enrichment and high-yield area for ECBM development and CO₂ geological storage in the study area.

Shales can form a complex fracture network during hydraulic fracturing, which greatly increases the stimulated reservoir volume (SRV) and thus significantly increases oil or gas production. It is therefore important to accurately predict the probability of formation of the hydraulic fracture network for shale gas exploration and exploitation. Conventional discriminant criteria are presented as the relationship curves of stress difference vs. intersection angle. However, these methods are inadequate for application in the field. In this study, an effective and quantitative prediction method relating to the probability of complex fracture network formation is proposed. First, a discriminant criterion of fracture network was derived. Secondly, Monte Carlo simulation was applied to calculate the probability of the formation of the complex fracture network. Then, the method was validated by applying it to individual wells of two active shale gas blocks in the Sichuan Basin, China. Results show that the probabilities of fracture network are 0.98 for well JY1 and 0.26 for well W204, which is consistent with the micro-seismic hydraulic fracturing monitoring and actual gas production. Finally, the method was further extended to apply for the regional scale of the Sichuan Basin, where the general probabilities of fracture network formation are 0.32−1 and 0.74−1 for Weiyuan and Jiaoshiba blocks, respectively. The Jiaoshiba block has, therefore, an overall higher probability for formation of fracture network than the Weiyuan block. The proposed method has the potential in further application to evaluation and prediction of hydraulic fracturing operations in shale reservoirs.

The pore structure of caprock plays an important role in underground gas storage security, as it significantly influences the sealing capacity of caprock. However, the pore structure evolution of caprock with the cyclic stress perturbations triggered by the cyclic gas injection or extraction remains unclear. In this study, the pore structure changes of mudstone caprock under cyclic loading and unloading were obtained by the nuclear magnetic resonance (NMR) tests system, then the influence of the changes on the breakthrough pressure of caprock was discussed. The results indicated that the pore structure changes are depending on the stress loading-unloading path and stress level. In the first cyclic, at the loading stage, with the increase of confining stress, the NMR T₂ spectra curve moved to the left, the NMR signal amplitude of the first peak increased, while the amplitude of the second peak decreased gradually. This indicated that the larger pores of mudstone are compressed and transformed into smaller pores, then the number of macropores decreased and the number of micro- and meso-pores increased. For a certain loading-unloading cycle, the porosity curve of mudstone in the loading process is not coincide with that in the unloading process, the porosity curve in the loading process was located below that in the unloading process, which indicated that the pore structure change is stress path dependent. With the increase of cycle numbers, the total porosity shown an increasing trend, indicating that the damage of mudstone occurred under the cyclic stress load-unload effects. With the increase of porosity, the breakthrough pressure of mudstone decreased with the increase of the cyclic numbers, which may increase the gas leakage risk. The results can provide significant implication for the underground gas storage security evaluation.

In this study, we systematically studied the occurrence regularity of in situ stress in the Pingdingshan mine. The critical criterion model of coal-rock destabilization was established based on the theoretical framework of fracture mechanics. Furthermore, we analyzed the coupling destabilization mechanism of in situ stress and gas and studied the influence of the variation between original rock stress and mining-induced stress on the critical criterion. Through field experiments and applications, we established a three-dimensional gas drainage technology system for areas with a large mining height and long work face. Based on our research, a demonstration project was developed for deep mine dynamic disaster control. The technical system included the arrangement and optimization of pre-drainage holes along the coal seam, technology, and optimization of gas drainage through the bottom drainage tunnel and upper corner, gas drainage technology through sieve tubes, and a two plugging with one injection under pressure sealing technology. The implementation of the demonstration project effectively reduced the gas content and pressure of the coal seam in the deep mine, and the project increased the critical strength of the instability and failure of coal and rock.

The positive S-isotopic excursion of carbonate-associated sulfate (δ³⁴S_CAS) is generally in phase with the Steptoean positive carbon isotope excursion (SPICE), which may reflect widespread, global, transient increases in the burial of organic carbon and pyrite sulfate in sediments deposited under large-scale anoxic and sulphidic conditions. However, carbon-sulfur isotope cycling of the global SPICE event, which may be controlled by global and regional events, is still poorly understood, especially in south China. Therefore, the δ¹³C_PDB, δ¹⁸O_PDB,δ³⁴S_CAS, total carbon (TC), total organic carbon (TOC) and total sulfate (TS) of Cambrian carbonate of Waergang section of Hunan Province were analyzed to unravel global and regional controls on carbon-sulfur cycling during SPICE event in south China.

The δ³⁴S_CAS values in the onset and rising limb are not obviously higher than that in the preceding SPICE, meanwhile sulfate (δ³⁴S_CAS) isotope values increase slightly with increasing δ¹³C_PDB in rising limb and near peak of SPICE (130–160 m). The sulfate (δ³⁴S_CAS) isotope values gradually decrease from 48.6‰ to 18‰ in the peak part of SPICE and even increase from 18‰ to 38.5% in the descending limb of SPICE. The abnormal asynchronous C-S isotope excursion during SPICE event in the south China was mainly controlled by the global events including sea level change and marine sulfate reduction, and it was also influenced by regional events such as enhanced siliciclastic provenance input (sulfate), weathering of a carbonate platform and sedimentary environment. Sedimentary environment and lithology are not the main reason for global SPICE event but influence the δ¹³C_PDB excursion-amplitude of SPICE. Sea level eustacy and carbonate platform weathering probably made a major contribution to the δ¹³C_PDB excursion during the SPICE, in particularly, near peak of SPICE. Besides, the trilobite extinctions, anoxia, organic-matter burial and siliciclastic provenance input also play an important role in the onset, early and late stage of SPICE event.

Carbon capture, utilization, and storage (CCUS) is considered one of the most effective measures to achieve net-zero carbon emissions by 2050, and low-rank coal reservoirs are commonly recognized as potential CO₂ storage sites for carbon sequestration. To evaluate the geological CO₂ sequestration potential of the low-rank coal reservoirs in the southern margin of the Junggar Basin, multiple experiments were performed on coal samples from that area, including high-pressure mercury porosimetry, low-temperature N₂ adsorption, overburden porosity and permeability measurements, and high-pressure CH₄ and CO₂ isothermal adsorption measurements. Combined with the geological properties of the potential reservoir, including coal seam development and hydrodynamic characteristics, the areas between Santun River and Sigong River in the Junggar Basin were found to be suitable for CO₂ sequestration. Consequently, the coal-bearing strata from Santun River to Sigong River can be defined as “potentially favorable areas for CO₂ sequestration”. To better guide the future field test of CO₂ storage in these areas, three CO₂ sequestration modes were defined: 1) the broad syncline and faulted anticline mode; 2) the monoclinic mode; 3) the syncline and strike-slip fault mode.

CO₂ geological storage and utilization (CGSU) is considered a far-reaching technique to meet the demand of increasing energy supply and decreasing CO₂ emissions. For CGSUs related to shale gas reservoirs, experimental investigations have attracted variable methodologies, among which low-field NMR (LF-NMR) is a promising method and is playing an increasingly key role in reservoir characterization. Herein, the application of this nondestructive, sensitive, and quick LF-NMR technique in characterizing CGSU behavior in shale gas reservoirs is reviewed. First, the basic principle of LF-NMR for ¹H-fluid detection is introduced, which is the theoretical foundation of the reviewed achievements in this paper. Then, the reviewed works are related to the LF-NMR-based measurements of CH₄ adsorption capacity and the CO₂-CH₄ interaction in shale, as well as the performance on CO₂ sequestration and simultaneous enhanced gas recovery from shale. Basically, the reviewed achievements have exhibited a large potential for LF-NMR application in CGSUs related to shale gas reservoirs, although some limitations and deficiencies still need to be improved. Accordingly, some suggestions are proposed for a more responsible development of the LF-NMR technique. Hopefully, this review is helpful in promoting the expanding application of the LF-NMR technique in CGSU implementation in shale gas reservoirs.

CCUS (carbon capture, utilization, and storage) technology is regarded as a bottom method to achieve carbon neutrality globally. CO₂ storage in deep coal reservoirs serves as a feasible selection for CCUS, and its storage potential can be attributed to the CO₂ adsorption capacity of the coal. In this paper, a series of CO₂ adsorption isotherm experiments were performed at different pressures and temperatures in sub-bituminous coal from the southern Junggar Basin (reservoir temperature ~25.9°C and pressure ~3.91 MPa). In addition, the high-pressure CO₂ adsorption characteristics of the southern Junggar Basin coal were characterized using a supercritical D-R adsorption model. Finally, the CO₂ storage capacities in sub-bituminous coal under the in situ reservoir temperature and pressure were analyzed. Results indicated that the excess adsorption capacities increase gradually with increasing injection pressure before reaching an asymptotic maximum magnitude of ~34.55 cm³/g. The supercritical D-R adsorption model is suitable for characterizing the excess/absolute CO₂ adsorption capacity, as shown by the high correlation coefficients > 0.99. The CO₂ adsorption capacity increases with declining temperature, indicating a negative effect of temperature on CO₂ geological sequestration. By analyzing the statistical relationships of the D-R adsorption fitting parameters with the reservoir temperature, a CO₂ adsorption capacity evolution model was established, which can be further used for predicting CO₂ sequestration potential at in situ reservoir conditions. CO₂ adsorption capacity slowly increases before reaching the critical CO₂ density, following a rapid decrease at depths greater than ~800 m in the southern Junngar Basin. The research results presented in this paper can provide guidance for evaluating CO₂ storage potential in deep coal seams.

Injecting carbon dioxide CO₂ into a coal seam is an important way to improve coalbed methane recovery and to store geological carbon. The fracture mechanical characteristics of bituminous coal determine the propagation and evolution of cracks, which directly affect CO₂ storage in coal seams and the efficiency of resource recovery. This study applied CO₂ adsorption and three-point bending fracture experiments using bituminous coal samples in a gaseous state (4 MPa), subcritical state (6 MPa), and supercritical state (8 and 12 MPa) to investigate the influence of CO₂ state and anisotropy on the fracture-related mechanical response of bituminous coal. The results show that the change in mechanical properties caused by CO₂ adsorption is CO₂ state-dependent. The supercritical CO₂ adsorption at 8 MPa causes the largest decrease in the mode-I fracture toughness (K_IC), which is 63.6% lower than the toughness before CO₂ adsorption. The instability characteristics of bituminous coal show the transformation trend of “sudden-gradual-sudden fracture”. With or without CO₂ adsorption, the order of the K_IC associated with three types of bituminous coal specimens is crack-divider type > crack-arrester type > crack-short transverse type. Phenomenologically, the fracture toughness of bituminous coal is positively correlated with its specific surface area and total pore volume; the toughness is negatively correlated with its average pore size.

Injecting external CO₂ into soft and low-permeability coal seams can improve CH₄ extraction efficiency, and also benefit in CO₂ sequestration. However, the distribution law of damage zone around borehole in soft coal seam and its effect on the efficiency of CO₂ injection promoted CH₄ extraction are not clear. In this paper, a multi-physics coupling mathematical model considering damage effect is established for simulating the process of CO₂ injection promoted CH₄ extraction in soft and low-permeability coal seam. The distribution of damage zone and permeability around boreholes under different diameters and coal strengths are analyzed. The gas pressure and gas content in coal seam during CO₂ injection promoted CH₄ extraction when the model considered damage effect are compared with that of ignored. The results show that small borehole diameter corresponds to narrow damage zone around the borehole in coal seam. The damage zone expands with the increase of the borehole diameter. The damage zone increases exponentially with the borehole diameter, while decreases exponentially with the compressive strength of coal seam. The highest permeability in the damage zone has increased by nearly 300 times under the condition of simulated case. CH₄ pressure around the extraction borehole reduces, and the reduction area expands with the increase of time. Compared with the result of considering the damage effect, the reduction area of ignoring it is smaller, and the reducing speed is slower. The integrated effect of CO₂ injection and CH₄ extraction leads to rapid decrease of CH₄ content in coal seam near the boreholes. The CO₂ pressure and content increase around the injection borehole, and the increasing area gradually extends to the whole coal seam. In soft coal seams, failure to consider the damage effect will underestimate the efficiency of CH₄ extraction and CO₂ sequestration, resulting conservative layout of boreholes.

To compare the pore structure, mechanical and CO₂ adsorption properties of coal and shale, a series of experiments were carried out using nuclear magnetic resonance (NMR), uniaxial compression, Brazilian splitting, and high-pressure CO₂ adsorption. The results show that the total porosity of coal is 7.51 times that of shale, and shale is dominated by adsorption pores, while adsorption pores and seepage pores in coal are equally important. Moreover, it is found that the micropores in shale are more advantageous, while meso-macropore in coal are more significant. The adsorption pore surface of coal is rougher than that of shale, and the seepage pore structure of shale is more complex. The uniaxial compressive strength, elastic modulus and absorption energy of shale are 2.01 times, 2.85 times, and 1.27 times that of coal, respectively, indicating that shale has higher compressive capacity and resistance to elastic deformation than coal. The average tensile strength, Brazilian splitting modulus, absorbed energy and brittleness index of shale are 7.92 times, 6.68 times, 10.78 times, and 4.37 times that of coal, respectively, indicating that shale has higher tensile strength and brittleness, but lower ductility, compared with coal. The performed analyses show that under the same conditions, the CO₂ adsorption capacity of coal is greater than that of shale. The present article can provide a theoretical basis to implement CO₂-enhanced coalbed methane (CBM)/shale gas extraction.

CO₂ flooding can significantly improve the recovery rate, effectively recover crude oil, and has the advantages of energy saving and emission reduction. At present, most domestic researches on CO₂ flooding seepage experiments are field tests in actual reservoirs or simulations with reservoir numerical simulators. Although targeted, the promotion is poor. For the characterization of seepage resistance, there are few studies on the variation law of seepage resistance caused by the combined action in the reservoir. To solve this problem, based on the mechanism of CO₂, a physical simulation experiment device for CO₂ non-miscible flooding production manner is designed. The device adopts two displacement schemes, gas-displacing water and gas-displacing oil, it mainly studies the immiscible gas flooding mechanism and oil displacement characteristics based on factors such as formation dip angle, gas injection position, and gas injection rate. It can provide a more accurate development simulation for the actual field application. By studying the variation law of crude oil viscosity and start-up pressure gradient, the characterization method of seepage resistance gradient affected by these two factors in the seepage process is proposed. The field test is carried out for the natural core of the S oilfield, and the seepage resistance is described more accurately. The results show that the advancing front of the gas drive is an arc, and the advancing speed of the gas drive oil front is slower than that of gas drive water; the greater the dip angle, the higher the displacement efficiency; the higher the gas injection rate is, the higher the early recovery rate is, and the lower the later recovery rate is; oil displacement efficiency is lower than water displacement efficiency; taking the actual core of S oilfield as an example, the mathematical representation method of core start-up pressure gradient in low permeability reservoir is established.

In situ stress testing can improve the safety and efficiency of coal mining. Identifying the Kaiser effect point is vital for in situ stress calculations; however, the in situ stress calculation is limited by the rock sampling angle. Here, the Kaiser effect point identification theory is established and applied to the Xuyong Coal Mine. Uniaxial compression and acoustic emission experiments were carried out on sandstone with 6 sampling directions. Furthermore, COMSOL simulation is applied to study the in situ stress distribution in the coal mine to verify the calculation accuracy. The results are as follows. 1) The failure mode of non-bedded and vertical-bedded rocks is primarily tensile shear failure with obvious brittleness in mechanical and acoustic emission characteristics. Shear slip along the bedding plane is the primary failure mode of inclined-bedded rock. Additional take-off points exist in the AE count curve. 2) The Kaiser point identification method based on the variation of AE count curve parameters \mathrm{\Delta }{t}_i and {\tau }_i can effectively calculate the in situ stress. According to the numerical value of Kaiser point and sampling direction, the in situ stress of the conveyor roadway in the Xuyong Coal Mine was calculated as {\sigma }_1=22.81\mathrm{M}\mathrm{P}\mathrm{a}, {\sigma }_2=10.87\mathrm{M} \mathrm{P}\mathrm{a} and {\sigma }_3=6.14\mathrm{M} \mathrm{P}\mathrm{a}. 3) By the COMSOL simulation study, it was found that a stress concentration zone of 16.13 MPa exists near the two sides roadway. Compared with the Kaiser effect method, the deviation rates of the three-direction principal stress calculated by COMSOL were all less than 5%. This verifies that the in situ stress calculation by Kaiser effect in this study can be applied to the Xuyong Coal Mine.

Injection of gas (CO₂) into coal seams is an effective method to benefit from both CO₂ geological storage and coalbed methane recovery. Based on the dual pore structure of coal mass, and the Weibull distribution of fracture permeability, a thermal-hydraulic-mechanical (THM) coupling mathematical model is proposed involving the non-isothermal adsorption of binary gases, dynamic gas diffusion between matrix and fractures, multiphase seepage, coal deformation, heat conduction and heat convection. This mathematical model is applied to study the process of CO₂-enhanced coalbed methane recovery (CO₂-ECBM). Results show that the CH₄ content of CO₂-ECBM in coal seam decreases significantly when compared with that of regular drainage, and decreases rapidly in the early stage but slowly in the later stage. Coal seam permeability evolution is triggered by changes in gas adsorption/desorption, temperature and effective stress. For regular drainage, the early permeability shows a decreasing trend dominated by the increase of effective stress, while the later permeability shows an increasing trend dominated by the CH₄ desorption caused shrinkage of coal matrix. For CO₂-ECBM, the permeability in coal seam generally shows a downward trend due to both matrix swelling induced by gas adsorption and thermal expansion, particularly near injection well. There appears an increased and delayed peak production rate of CH₄. The CH₄ production rate of CO₂-ECBM is always higher than that of regular drainage. The CH₄ cumulative production and CO₂ cumulative storage linearly increase with time, and the CH₄ cumulative production of CO₂-ECBM increased by 39.2% in the duration of 5000 d compared with regular drainage. Reasonable CO₂ injection starting time can overcome the issue of early CO₂ breakthrough and ineffective increase of CH₄ production. In the studied case, the optimal injection starting time is 2500 d. Compared with the simultaneous CH₄ extraction and CO₂ injection, the CH₄ cumulative production of optimal time has increased by 30.1%. The research provides a reference for determining the reasonable CO₂ injection time under similar conditions.

Carbon capture, utilization, and storage (CCUS) have garnered extensive attention as a target of carbon neutrality in China. The development trend of international CCUS projects indicates that the cluster construction of CCUS projects is the main direction of future development. The cost reduction potential of CCUS cluster projects has become a significant issue for CCUS stakeholders. To assess the cost reduction potential of CCUS cluster projects, we selected three coal-fired power plants in the coastal area of Guangdong as research targets. We initially assessed the costs of building individual CCUS projects for each plant and subsequently designed a CCUS cluster project for these plants. By comparing individual costs and CCUS cluster project costs, we assessed the cost reduction potential of CCUS cluster projects. The results show that the unit emission reduction cost for each plant with a capacity of 300 million tonnes per year is 392.34, 336.09, and 334.92 CNY/tCO₂. By building CCUS cluster project, it could save 56.43 CNY/tCO₂ over the average cost of individual projects (354.45 CNY/tCO₂) when the total capture capacity is 9 million tonnes per year (by 15.92%). Furthermore, we conducted a simulation for the scenario of a smaller designed capture capacity for each plant. We found that as the capture scale increases, the cost reduction potential is higher in the future.

The permeability and its horizontal anisotropy induce a critical influence on staged CH₄ output inhibition process. However, a quantitative evaluation of this influence has been rarely reported in the literature. In this work, the impact of horizontal anisotropic permeability on CO₂-ECBM was numerically investigated. The variation in the staged CH₄ output inhibition was analyzed. The ideal displacement profile of the CO₂-ECBM process was established for the first time. Moreover, the variation in CH₄ output of different wellbores was discussed. The results showed that 1) low-permeable or weak-anisotropic reservoirs were not conducive to enhanced CH₄ recovery owing to long inhibition time (> 1091 days) and high inhibition level (> 36.9%). As permeability and anisotropy increased, due to the accelerated seepage of free water, the hysteresis time and inhibition time could decrease to as short as 5 days and 87 days, respectively, and the inhibition level could weaken to as low as 5.00%. Additionally, the CH₄ output and CO₂ injection could increase significantly. 2) Nevertheless, high permeability and strong anisotropy easily induced CO₂ breakthrough, resulting in lower CH₄ production, CO₂ injection and CO₂ storage than expected. While maintaining high efficiency of CO₂ storage (> 99%), upregulating CO₂ breakthrough concentration from 10% to 20% might ease the unfavorable trend. 3) Along the direction of fluid flow, the ideal displacement profile consisted of CO₂ enriched bank, CO₂ and CH₄ mixed bank, CH₄ enriched bank, and water enriched bank, whereas a remarkable gap in the displacement profiles of the dominant and non-dominant seepage directions was observed. 4) The potential of CH₄ output might vary greatly among different wellbores. The producers along the dominant seepage direction held more potential for CH₄ recovery in the short-term, while those along the non-dominant seepage direction avoided becoming invalid only if a long-time injection measure was taken for the injectors. These findings pave the way to understand fluid seepage in real complex reservoirs during CO₂-ECBM and conduct further field projects.

Due to the limited permeability and high methane content of the majority of China’s coal seams, significant coal mining gas disasters frequently occur. There is an urgent need to artificially improve the permeability of coalbed methane (CBM) reservoirs, enhance the recovery efficiency of CBM and prevent mine gas accidents. As a novel coal rock fracture technology, the CO₂ phase transition jet (CPTJ) has been widely used due to its advantages of safety and high fragmentation efficiency. In this study, to ascertain the effects of the pressure of CPTJ fracturing, the influence of its jet pressure on cracked coal rock was revealed, and its effect on CBM extraction was clarified. In this research, the law of CPTJ pressure decay with time was investigated using experimental and theoretical methods. Based on the results, the displacement and discrete fracture network law of CPTJ fracturing coal rock under different jet pressure conditions were studied using particle flow code numerical simulation. Finally, field experiments were conducted at the Shamushu coal mine to assess the efficiency of CPTJ in enhancing CBM drainage. The results showed that the pressure of the CPTJ decreased exponentially with time and significantly influenced the number and expansion size of cracks that broke coal rock but not their direction of development. CPTJ technology can effectively increase the number of connected microscopic pores and fractures in CBM reservoirs, strongly increase the CBM drainage flow rate by between 5.2 and 9.8 times, and significantly reduce the CBM drainage decay coefficient by between 73.58% and 88.24%.

CO₂ immiscible flooding is an environmentally-friendly and effective method to enhance oil recovery in ultra-low permeability reservoirs. A mathematical model of CO₂ immiscible flooding was developed, considering the variation in crude oil viscosity and starting pressure gradient in ultra-low permeability reservoirs based on the non-Darcy percolation theory. The mathematical model and numerical simulator were developed in the C++ language to simulate the effects of fluid viscosity, starting pressure gradient, and other physical parameters on the distribution of the oil pressure field, oil saturation field, gas saturation field, oil viscosity field, and oil production. The results showed that the formation pressure and pressure propagation velocity in CO₂ immiscible flooding were lower than the findings without considering the starting pressure gradient. The formation oil content saturation and the crude oil formation viscosity were higher after the consideration of the starting pressure gradient. The viscosity of crude oil considering the initiation pressure gradient during the formation was higher than that without this gradient, but the yield was lower than that condition. Our novel mathematical models helped the characterization of seepage resistance, revealed the influence of fluid property changes on seepage, improved the mathematical model of oil seepage in immiscible flooding processes, and guided the improvement of crude oil recovery in immiscible flooding processes.