CO2 injection is a promising approach for enhanced gas recovery (EGR) in tight sandstone reservoirs, yet the resulting CO2-CH4 transport can be strongly affected by heterogeneity and pore-domain methane mobilization. In this study, CO2-CH4 displacement experiments were performed on one single tight sandstone core and three axially heterogeneous composite tight sandstone cores under the same reservoir pressure and temperature conditions. In-situ nuclear magnetic resonance (NMR) and magnetic resonance imaging (MRI) were used to monitor methane mobilization, and the volume-averaged concentration responses were interpreted using the classical advection-dispersion equation (ADE) and a mobile-immobile model (MIM). Methane-saturated NMR T2 spectra show bimodal distributions, with short-T2 components associated with nano- and micro-pores dominating the pore volume of the tight sandstones. During CO2 injection, methane is preferentially mobilized from the long-T2 components, indicating earlier recovery from relatively larger or better-connected pores. Compared with the single core, the composite cores show pronounced suppression of methane mobilization in relatively-small pores, resulting in lower recovery and uneven displacement. For the transport modeling, both ADE and MIM were applied in an equivalent one-dimensional formulation, and results show that axial heterogeneity can cause non-ADE transport, but MIM is not always required. ADE remains sufficient when methane mobilization from the short- and long-T2 components is relatively balanced, even in composite cores with high permeability contrast. Composite cores with strongly suppressed small-pore mobilization show delayed concentration evolution and long-tailing effect, which are better described by MIM. These results suggest that pore-domain methane mobilization and pore-structure-controlled domain separation should be considered, in addition to permeability contrast, when selecting transport models for CO2–CH4 flow in tight sandstones. This is relevant to reservoir-scale modeling, where permeability contrast alone may not fully describe delayed gas exchange and non-ADE transport behavior.

Abstract To investigate the water and gas flow patterns throughout the entire development life cycle of a water-drive gas reservoir, as well as to evaluate the enhanced gas recovery (EGR) effects of carbon dioxide (CO2) and surfactant injection, long-core displacement experiments under different permeabilities and depletion pressures before gas injection were conducted using a self-designed experimental setup for simulating inclined bottom-water gas reservoirs. Additionally, nuclear magnetic resonance (NMR) technology was employed to study the fluid occurrence states during the entire development life cycle of the gas reservoir. Studies show that for medium-to-high permeability bottom-water gas reservoirs, during the water-flooding depletion development stage, the favorable water–gas mobility ratio stabilizes the water–gas displacement front, making this the main stage of gas reservoir production. The recovery factor can reach 59.91–73.19%; however, an excessively high permeability can lead to severe water channeling, thereby reducing the recovery factor. The recovery factor of the relatively high-permeability core sample (19.1 mD) during the water influx stage is 13.26% lower than that of the relatively low-permeability core sample (4.0 mD). The water drainage gas production stage can further increase the recovery factor by 5.52–9.13%, which is conducive to subsequent gas/chemical injection-enhanced recovery. When the gas reservoir is depleted to a certain pressure (40 or 60% of the initial formation pressure), switching to the CO2 injection stage can further improve the recovery factor by 3.51–4.73% before CO2 breakthrough. Under the same conditions, a later depletion pressure before gas injection (40 versus 60% of the initial pressure) releases greater natural energy and discharges more water to increase the recovery factor by 7.59% during the dewatering gas production stage. Sufficient dewatering can also enhance the gas-phase flow capacity to increase the recovery factor by approximately 4.72% during the CO2 injection stage. The main role of CO2 injection is to replenish energy and release water trapping; once breakthrough occurs, the gas recovery factor increases significantly but the methane concentration drops rapidly. After CO2 injection, due to the small amount of remaining gas, the effect of switching to surfactant flooding is limited, only increasing the recovery factor by 0.27–1.22%. Results from on-site NMR transverse relaxation time (T2) spectroscopy of core samples during the full-life-cycle experiment indicate that during the water-flooding depletion stage, macropores, mesopores, small pores, and micropores are well-produced. In the CO2 injection and surfactant-enhanced recovery stages, mesopores are further produced. This reveals that methane production follows the ″all-to-mesopore″ pore-utilization sequence. The above results in this study were obtained from relatively homogeneous and small core plugs; therefore, the experimental conclusions cannot be fully extrapolated to actual gas reservoirs with strong reservoir heterogeneity and large scale. However, the relative performance trends among different schemes can provide directional guidance for field decisions. In the future, large-scale laboratory experiments or actual well-pattern field trials should be expanded.

Starting from the first principle thinking,this study systematically reviews the development mechanisms of gas reservoirs and proposes the development concept of"full lifecycle enhanced gas recovery(EGR)".Following the principles of scientificity,practicality and comparability,a generational classification system for EGR technologies is established.The research indicates that the properties of natural gas dictate a development mechanism primarily driven by pressure depletion to release the elastic expansion energy of gas.This leads to a development model centered on primary depletion,supplemented by limited adjustments in late stages.Early development essentially lies in well pattern optimization and risk pre-control,while late development focuses on targeted local adjustments and integrated collaborative control.Primary gas recovery,relying on natural energy depletion,achieves a recovery factor of 25％-55％.Secondary gas recovery,through active regulation of the reservoir pressure field via techniques like blockage removal,and injection-production optimization,can enhance the recovery factor by 10-15 percentage points.Tertiary gas recovery,employing multiple mechanisms to alter the reservoir's physical and chemical fields synergistically,offers a potential further increase of 5-10 percentage points.Currently,primary recovery technologies are mature and well-established.Synergistic optimization of well patterns and fracture networks enables effective production from gas-drive reservoirs,while optimized development strategies facilitate orderly production from water-drive gas reservoirs.Secondary recovery technologies,in the field pilot stage currently,adopt active measures like enhanced water drainage,water shutoff,and gas injection to effectively control water influx and release trapped gas.Tertiary recovery remains largely in the laboratory or pilot test stage.Future efforts should focus on cross-generational technologies,such as"primary+secondary"and"primary+tertiary"combinations,to continuously improve recovery factors throughout the full lifecycle of gas reservoirs.

Addressing the problem of limited methane (CH4) recovery degree under different production conditions in a target low-permeability carbonate gas reservoir, this study intends to further investigate the effect of carbon dioxide (CO2) injection on enhanced gas recovery (EGR). A group of long-core physical simulation experiments of CO2 injection for EGR was adopted. Field injection–production parameters were converted to laboratory conditions through similarity criteria to simulate the actual production process of gas wells. Systematic experiments on CH4 depletion and CO2 displacement were carried out under different irreducible water saturation, gas injection timing pressure and injection rates. The influence laws of each key parameter on the CO2 breakthrough time and CH4 recovery degree were analyzed emphatically, and the optimal injection–production scheme was obtained. For the target low-permeability carbonate gas reservoir (permeability < 1 mD), the optimal CO2 injection scheme is as follows: for layers with medium to high irreducible water saturation (≥40%), CO2 injection at a rate of 36,000 m3/d per well after the end of stable production (formation pressure > 7.38 MPa) can increase the CH4 recovery degree by 3–5%. This study provides experimental support for the optimization of CO2 injection schemes for enhanced recovery in gas reservoirs and the adjustment of gas reservoir development strategies under different irreducible water saturation conditions.

Sandstone serves as a vital medium for CO2 geological storage. Wettability is a key parameter in assessing the CO2 storage capacity and the safety of sequestration within sandstone reservoirs. This article offers a comprehensive review of the mechanism underlying the wettability alteration (WA) in sandstone reservoirs subsequent to CO2 injection. It commences by reviewing the classification of wettability in sandstone reservoirs, elucidating the pros and cons of diverse methods and techniques used to measure sandstone wettability. Special attention is then given to the analysis of crucial parameters, including the phase state of CO2, storage conditions, initial wetting state, and chemical reactions. Their impacts on the WA of the CO2/brine/sandstone system are thoroughly evaluated. The paper also presents an overview of the latest research advancements in contact angle characterization through different methods over the years. It identifies the knowledge gaps existing in the inconsistent results of various characterization methods and in understanding the WA mechanism. Consequently, it proposes the imperative need for multi-scale quantitative wettability characterization and enhanced research on the wettability alteration mechanism. Finally, it underscores the significant influence of WA on the CO2 residual storage capacity. This review provides a valuable reference for the selection of optimal formations for future CO2 sequestration, as well as for the further assessment and implementation of CO2 geological storage projects.

The Upper Permian Changxing Formation at the southern margin of the Kaijiang-Liangping Trough (NE Sichuan Basin) is characterized by small-scale, thin, and scattered reef-shoal complexes, resulting in strong stratigraphic heterogeneity. Conventional qualitative methods struggle to achieve accurate high-frequency sequence division due to limited core data. To address this, we integrate INPEFA (Integrated Prediction Error Filter Analysis) with wavelet transform techniques using drilling and logging data to establish a high-resolution sequence stratigraphic framework for the Changxing Formation. The formation is subdivided into two third-order sequences and six fifth-order sequences (PSS1–PSS6). Results demonstrate a strong sequence control on reef-shoal development: reefs and bioclastic shoals are preferentially developed at the tops of fifth-order highstand systems tracts (HST). This integrated approach significantly improves sequence division accuracy in complex carbonate successions and provides a methodological reference for high-resolution sequence stratigraphic analysis in similar stratigraphically complex settings globally.

Gas transport in heterogeneous porous media often deviates from classical descriptions due to pore-scale heterogeneity and multiscale transport processes, which is particularly relevant for CO2-CH4 displacement and mixing in subsurface energy and storage applications. In this study, we investigate CO2-CH4 transport behavior in carbonate composite cores through a combined experimental and modeling approach. Gas injection experiments are carried out under reservoir conditions on axially connected carbonate cores, and in situ Nuclear magnetic resonance (NMR) measurements are used to track time-resolved, volume-averaged concentration evolution. NMR T2 distributions are used to characterize pore-size-dependent mobility and to independently constrain permanently immobile pore domains. The three transport formulations are implemented as equivalent one-dimensional models and solved using finite-difference methods to analyze the composite cores without explicit segmentation. The time-fractional advection-dispersion equation is used as the primary model and compared with the classical advection-dispersion equation and a single-rate mobile-immobile mass-transfer formulation under identical boundary conditions and effective dead-volume constraints. Comparisons with experimental observations indicate that gas transport in the carbonate composites exhibits clear non-Fickian behavior, characterized by long-tailed concentration evolution and delayed mixing that cannot be captured by the classical advection-dispersion equation. Both the single-rate mobile-immobile and time-fractional model capture the anomalous transport behavior, but the mobile-immobile parameters are not uniquely constrained, whereas the fractional-order model provides a compact description using the fractional order and effective dispersion coefficient. A tight sandstone composite core is analyzed as a reference case and shows a much weaker deviation from Fickian behavior, suggesting that gas transport is confined to a narrower range of timescales. Root-mean-square displacement results further show that carbonate transport is dominated by temporal delays with limited spatial spreading, while tight sandstone transport spans a substantial fraction of the core but remains pre-asymptotic within the experiment window.

There is little research on the strain characteristics of ultradeep dolomite rocks with deep burial, high stress, and developed fractures and macropores. This article comparatively studies the influence of stress and fracturing on the pore-throat structure of different types of ultradeep dolomite rocks by setting up stress experiments and fracturing experiments and using computed tomography (CT) scanning. In the stress experiment, the fluid-solid coupling effect on pore space was considered. The study shows that unlike shallow to medium carbonate reservoirs, when the stress is high but lower than the rock yield stress and in a flowing state, the studied ultradeep dolomite rock has a higher permeability after recovery from compression. When the stress is high, brittle deformation occurs inside the rock sample, and dolomite particles in the macropores are crushed and detached, blocking the middle pores with the gas flow; the two adjacent mesopores are merged into one macropore. In this way, the average pore size of the rock sample increases and the proportion of macropore volume increases. The increase in macropores plays a leading role in improving the reservoir's permeability. The edges of dolomite crystals are compressed open under high stress, resulting in more developed intercrystalline fractures, larger fracture widths, and strengthened communication between fractures. Besides the effect of stress, the fractures generated by fracturing greatly expand and connect the existing fractures, and then improve the connectivity of the reservoir, which is the main factor leading to the improvement of reservoir permeability after fracturing. In addition, rock mechanical parameters were obtained through triaxial mechanics experiments. Dolomite rock samples that have undergone multiple cycles of stress cycling have more developed microfractures and macropores and weakened axial compression resistance and are more prone to be fractured. This study can provide a theoretical basis and guidance for the efficient development of ultradeep dolomite.

In order to improve the field gas recovery (FGR) and CO2 sequestration ratio (CSR) for the edge/bottom-water gas reservoirs, a hybrid framework is designed to combine Long Short-Term Memory (LSTM) with Non-dominated Sorting Genetic Algorithm II (NSGA-II) to obtain the optimal CO2 injection and production scheme at different injection and production rates. In this framework, the Latin hypercube sampling method is used to generate the training and testing samples within a given range of injection and production rates, and the corresponding results are obtained by a calling numerical simulator. The proxy model is obtained by using the samples generated from LSTM training to replace the numerical simulator and improve the simulation efficiency. NSGA-II is utilized to determine the Pareto front of the optimal outcomes to maximize FGR and CSR. The robustness of the framework is verified with a typical edge/bottom water-drive gas reservoir. CO2 sequestration process in this gas reservoir after 100 years is simulated based on the optimal solution. The results show that the R2 of the LSTM proxy model for FGR and CSR prediction is greater than 0.99, which indicates that it can replace the numerical simulator accurately. Compared with the basic scheme without optimization, FGR is increased by 6.09% and CSR is increased by 3.91%. Under the optimal scheme, the CO2 distribution for long-period storage is predicted, and the results show CO2 will eventually migrate to the bottom of the reservoir under the influence of gravity, which is contrary to CO2 sequestration in oil reservoirs. It can provide theoretical guidance for CO2 injection for enhanced gas recovery and sequestration in edge/bottom water-drive gas reservoirs.

Tight gas reservoirs are characterized by low porosity, low permeability, and strong heterogeneity. CO2 flooding, as an important approach for enhancing gas recovery while achieving carbon sequestration, is often restricted by gas channeling. Based on the sandstone reservoir parameters of the Shihezi Formation in the Ordos Basin, a two-dimensional fracture–matrix coupled numerical model was developed to systematically investigate the effects of fracture number, fracture inclination, fracture width, injection pressure, and permeability contrast on gas breakthrough time and sweep efficiency. A second-order regression model was further established using response surface methodology (RSM). The results show that a moderate fracture density can extend breakthrough time and improve sweep efficiency, while permeability contrast is the fundamental factor controlling gas channeling risk. When the contrast increases from 0.7 to 9.9, the breakthrough efficiency decreases from 88.5% to 68.9%. The response surface analysis reveals significant nonlinear interactions, including the coupled effects of fracture number with fracture width, injection pressure, and inclination angle. Under the optimized conditions, the breakthrough time can be extended to 46,984 h, with a corresponding sweep efficiency of 87.7%. These findings provide a quantitative evaluation method and engineering optimization guidance for controlling CO2 channeling in tight gas reservoirs.

Under the background of net-zero emissions, CCUS-EGR (carbon capture, utilization and storage & enhanced gas recovery) technology serves as a critical approach for enhancing gas recovery of tight gas reservoirs while reducing greenhouse gas emissions. Currently, the application of CCUS-EGR technology for tight gas reservoirs still remains the early stage of field trails, and it is necessary to evaluate the enhanced gas recovery efficiency and the carbon sequestration capacity of CCUS-EGR. Therefore, through PVT (pressure-volume-temperature) property analysis of CH4 (methane) and CO2 (carbon dioxide), laboratory-scale CCUS-EGR experiments using tight sandstone rock samples, theoretical equation derivation for recovery factor prediction, and numerical simulations of CCUS-EGR in tight gas reservoirs, the stimulation efficiency and CO2 sequestration capacity of CCUS-EGR in tight gas reservoirs in Ordos Basin were systematically analyzed. The following conclusions were drawn: (1) The density and viscosity of supercritical CO2 are significantly greater than those of CH4, and the diffusivity of CO2 under reservoir condition is relatively low, which is advantageous for its efficient displacement of CH4 within the gas reservoir. (2) After depleting rock cores to abandonment pressures of 10.0 MPa, 7.5 MPa, and 5.0 MPa, CO2 was injection into rock cores. When CO2 breakthrough occurred, the resulting recovery factor increments could reach 25.6%, 17.4%, and 10.7%, respectively; (3) The recovery factor increment of CCUS-EGR is mainly affected by four factors including sweep efficiency of pressure drop, depletion efficiency in depletion development stage, CO2 sweep efficiency and CO2 displacement efficiency. Because of the reservoir heterogeneity and gas channeling, these four factors are 47.2%, 61.0%, 38.5% and 87.3% respectively in the X pilot area, resulting in an estimated recovery factor increment of only 4.8%, which is close to the numerical simulation result (5.1%) and lower than the experimental result (25.6%); (4) Based on the proportional conversion of reserves in the pilot area, it is estimated that CCUS-EGR technology will increase tight gas production in Ordos Basin by approximately 1.3×1011 m3 and sequestrate about 8.49×108 tons of CO2. This paper systematically investigates the mechanisms of enhanced gas recovery and storage capacity of CCUS-EGR in tight gas reservoirs. The findings offer a valuable reference for promoting the application of CCUS-EGR technology in tight gas reservoirs in Ordos Basin, Northwest China.

At present, it is necessary to change the development method to improve the development of gas reservoirs entering the middle to late stage of development. CCUS-EGR can drive out residual gas while burying carbon, which is an economically feasible method. For most reservoirs, water intrusion is severe or there is a large amount of pore water, so it is necessary to study the impact of CO2-water–rock reaction on reservoir physical properties and pore structure. Rock sample displacement experiments were implemented, CO2 were injected into carbonate rock samples and tight sandstones saturated with bound water for displacement, and the changes in the permeability of the rock samples during the displacement process were monitored. The pore structure of rock samples before and after CO2 water rock reaction was measured using nuclear magnetic resonance equipment, and the different water rock reaction occurring in different rock types were studied combined with XRD testing. This study provides a reference for on-site CO2 injection testing. For carbonate rock samples mainly com-posed of dolomite and calcite, supercritical CO2 has a negative effect on the permeability of the rock samples. Under the temperature and pressure conditions of the reservoir, CO2 dissolves in water to form carbonic acid. Carbonic acid reacts with CaCO3 to form HCO3−/CO32− ions, which dissolve in the solution. When the HCO3− ions in the solution become supersaturated, calcium carbonate precipitates. The micropores in carbonate rocks are expanded by acid dissolution, while the macropores are filled by precipitated calcium carbonate. After injecting CO2 for 1175 min, the porosity of the rock sample decreased by 10.44

From traditional fossil fuels to future clean energy, natural gas is a very important bridge. Ultra-deep carbonate water-drive gas reservoir is an important part of natural gas development. Using a numerical simulator, a single well mechanism model considering the physical properties and seepage characteristics of the target ultra-deep carbonate water drive gas reservoir is established to study the influence of water body parameters, seepage parameters and fracturing measures on its development. The reservoir characteristic parameters and flow characteristic parameters suitable for the target ultra-deep gas reservoir are extracted from the existing experiments. Based on the experimental data, a single well mechanism model of the target ultra-deep carbonate gas reservoir is established using a numerical simulator. Use single well production data for production history matching, and find out the main control factors affecting the development of water drive gas reservoir in the process of history matching. Based on the historical production data of a single well, the production index of a single well in the next 10 years is predicted. The results show that for the target ultra-deep carbonate rock water flooding gas reservoir, reducing the volume of water body, reducing the velocity of water invasion, and lowering the gas-water interface are beneficial to reduce the water production rate, weaken the gas-water Jamin effect caused by water invasion, and reduce the depletion of near-wellbore pressure. After considering the high-velocity non-Darcy effect of gas, the gas production rate of gas wells decreases, while the water production rate increases, and a lot of pressure is consumed at the near-wellbore area of the gas reservoir. In this condition, it is a must to greatly reduce the bottomhole pressure of gas wells to achieve the target gas production rate. The gas-water two-phase permeability curve considering high pressure and high temperature increases both gas and water production rate, and making the historical matching results closer to the actual single well production data. Fracturing improves the gas-phase seepage capacity and alleviate the gas-water Jiamin effect in the near-wellbore area. Under the same gas production rate, the bottomhole pressure will increase significantly. But fracturing has little effect on the water production rate of the target gas well. The novelty of this study is that the mechanism model fully simulates the reserve characteristics and seepage characteristics of the target ultra-deep carbonate rock water drive gas reservoir by using experimental data considering reservoir temperature and pressure conditions. Studying the main controlling factors of the ultra-deep carbonate water-drive gas reservoir are conducive to formulating development technology policies for the efficient development of similar gas reservoirs.

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.

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.

The reservoir space, types and distribution characteristics of karst carbonate gas reservoirs in the fourth member of Sinian Dengying Formation (Deng 4 Member) in central Sichuan Basin are analyzed based on the drilling, logging and seismic data. A development model of karst reservoirs is constructed to support the high-efficiency development of gas pools. The research shows that the reservoirs in Deng 4 Member have mainly small-scale karst vugs and fractures as storage space, and can be divided into three types, fracture-vug, pore-vug and pore types. The development patterns of the karst reservoirs are determined. On the plane, the karst layers increase from 65 m to 170 m in thickness from the karst platform to the karst slope, and the high-quality reservoirs increase from 25.0 m to 42.2 m in thickness; vertically, the reservoirs at the top of Deng 4 Member appear in multiple layers, and show along-bedding and along fracture dissolution characteristics. The reservoirs at the bottom are characterized by the dissolution parallel to the water level during the karstification period, and have 3 ?5 large-scale fracture-cave systems. Based on the reservoir development characteristics and the genetic mechanism, three types of reservoir development models of karst reservoir are established, i.e., bed-dissolved body, fracture- dissolved body and paleohorizon-dissolved body. The construction of karst reservoir development models and seismic response characteristics of the three types of reservoirs can provide parameter for well placement and trajectory design, and substantially improve productivity and development indices of individual wells and gas reservoirs. The designed production capacity of the gas reservoir has enhanced from the initial 3.6 billion to 6 billion cubic meters, making the profit of the reservoir development increase noticeably.

The carbonate gas reservoir is one of the most important gas formation types; it comprises a large proportion of the global gas reserves and the annual gas production rate. However, a carbonate reservoir with weathering crust formation is rare, and it is of significant interest to illustrate the geological characteristics of this kind of formation and present the emerging problems and solution measures that have arisen during its exploitation. Therefore, in this research, a typical carbonate gas reservoir with weathering crust formation that is located in Ordos Basin, China, was comprehensively studied. In terms of formation geology, for this reservoir, the distribution area is broad and there are multiple gas-bearing layers with low abundance and strong heterogeneity, which have led to large differences in gas well production performance. Some areas in this reservoir are rich in water, which seriously affects gas well production. Regarding production dynamics, the main production areas in this gas reservoir have been stable on a scale of 5.5 billion cubic meters for more than a decade, and the peripheral area has been continually evaluated to improve production capacity. Nevertheless, after decades of exploration and development, the main areas of this reservoir are faced with several problems, including an unclear groove distribution, an unbalanced exploitation degree, low formation pressure, and increases in intermittent gas wells. To deal with these problems and maintain the stability of gas reservoir production, a series of technologies have been presented. In addition, several strategies have been proposed to solve issues that have emerged during the exploration and exploitation of peripheral reservoir areas, such as low-quality formation, unclear ancient land and complex formation-water distribution. These development measures employed in the carbonate gas reservoir with weathering crust formation in the Ordos Basin will surely provide some guidance for the efficient exploitation of similar reservoirs in other basins all over the world.

安岳气田灯影组四段为强非均质性碳酸盐岩气藏,面临储层非均质性强、气井产能差异大等众多难题.为了进一步提高气藏储量动用程度,采用动态和静态相结合、研究和管理并重的研究方法,综合地震、钻井、测井、生产动态等资料,深入分析了气藏地质特征和开发特征.研究结果表明,气藏地质特征为:①构造-沉积分异导致有效储层发育在平面上呈现出明显分区的特征;②优质储层的发育受沉积、岩溶和微裂缝3个因素综合控制;③由台缘向台内,地层岩性趋于复杂、储层变薄,储层非均质性变强.气藏开发特征为:①叠合岩溶发育导致气井产能在平面上具有明显分区分带特征;②储层强非均质性特征导致气井初期的高产与长期稳产能力不匹配;③特殊工艺井和分段酸压工艺可大幅度提高单井产量.在气藏特征分析的基础上,结合模型分析和同类气藏开发经验,确定开发技术对策:①多手段融合刻画气藏特征,明确优质储层发育特征,夯实储量基础;②全生命周期提高采收率,采用不规则井网,优选大斜度井、水平井井型,有针对性制定增产工艺方案,中—后期通过打补充井、地面增压、排水采气等多手段结合挖掘气藏开发潜力;③分单元管理提高气藏开发水平,以单井动态储量评价为核心制定开发指标,以气井类型划分为基础开展跟踪评价,以一体化布局为抓手提高管理水平,整体协同实现气藏高效开发.

天然气产业发展是促进能源消费结构由高碳化石能源为主体向无碳新能源为主体转变的桥梁和纽带,是实现第三次世界能源转型的关键.为加快我国天然气产业发展、构建新常态下安全、先进、高效的国家能源体系,在回顾世界天然气产业发展的基础上,站在能源体系转型的高度和历史发展的维度,从7大视角深刻剖析了世界天然气产业发展的动力,从4个方面全方位研判了世界天然气产业发展趋势.研究结果表明:①纵观世界天然气产业发展历程,天然气产业发展具有天然气自然属性、产业政策、上中下游的一体化协同三大驱动力;②世界能源体系形成"四分天下"的格局,天然气在能源结构中占比持续上升,大气田是世界天然气产量的基础和保障,天然气贸易呈现国际化、LNG与管道气均衡发展的形势,天然气在发电、工业燃料和城市燃气等终端消费领域用量持续上升;③"碳中和"与能源转型引领了世界天然气产业链全面发展,迎来天然气黄金发展期.结论认为,研究成果研判了世界天然气产业发展趋势,相关认识和建议不仅对我国天然气行业发展具有重要价值,而且对天然气在能源转型中作用的充分发挥具有指导意义.

Deviated wells are used to improve the performance of carbonate reservoirs with multiple heterogeneous layers and penetrate the “sweet spot” of each layer, which is full of fractures and vugs. It is difficult to consider in-layer and inter-layer heterogeneities simultaneously, and predict the production performance for these wells accurately. Therefore, a semi-analytical model to analyze the production performance of deviated wells in a multilayer heterogeneous stress-sensitive carbonate gas reservoir is proposed. For each layer, the inner region is a fractured-vuggy porous medium, while the outer region is merely a tight formation with matrix and formation properties, and penetrated inclination angles may be distinct. Pseudo-time/pressure factors are introduced to consider fracture stress sensitivity. Through the application of Laplace transformation, Fourier transform and inverse, Duhamel convolution, and Stehfest numerical inversion, the presented model is solved. The validity of this model is verified through comparison with single-layer composite formation with different porous mediums and vertical well in a multilayer carbonate gas reservoir. Moreover, by matching bottom-hole pressure data collected from a slanted well in the Anyue gas field, the applicability of this model is validated. A synthetic case, which has two composite formations, the first (upper) layer is more permeable than the second (lower) layer, is used to study the variations of inner region radius, fracture/matrix permeability, and inclination angles on production behaviors. The results show the properties of the first layer determine well bottom-hole pressure, whereas the rise of permeability, inner region radius and penetrated angle for the second layer can improve the gas recovery of this layer. In practice, to maintain well bottom-hole pressure with a relatively high level and enhance gas recovery of the tight layer, the inclination angle should be larger than 60° for each layer, and be increased to as large as possible. The findings of this study can help for a better understanding of the production behaviors of deviated wells in multilayer heterogenous reservoirs and could provide some guidance for the design of well trajectory.