To break through the technical bottlenecks constraining China’s natural gas supply, this study systematically reviews the feasible application scenarios of large-scale artificial intelligence (AI) models in natural gas exploration and development. Taking DeepSeek as an example, an approach integrating technology transfer with case study is adopted, to construct a technology transfer pathway suitable for the natural gas sector by summarizing the paradigm of DeepSeek in industry applications. Furthermore, based on the practices of domestic oil and gas enterprises, the application scenarios of foundation models are thoroughly demonstrated. The following results are obtained. (i) In terms of knowledge management, foundation models can establish intelligent Q&A systems, internalize vast amounts of unstructured data, systematize expert experiences, and significantly enhance decision-support efficiency. (ii) Regarding data processing and interpretation, the multimodal fusion capability of foundation models enables the unified handling of multi-source data such as seismic and logging data, achieving intelligent extraction of geological features and accurate reservoir characterization to facilitate “sweet spot” prediction. (iii) For engineering operations, computer vision-based intelligent recognition technology for core thin sections allows for automatic and objective geological description. (iv) In production optimization, time-series forecasting and reinforcement learning models are leveraged to achieve real-time field-wide scheduling, fault warning, and operational optimization, thereby improving oil and gas recovery. (v) The deployment of large-scale AI models in natural gas exploration and development still faces challenges in respect to data security, domain-specific knowledge integration, model generalization, and system integration. In conclusion, exemplified by DeepSeek, large-scale AI models provide a key technological pathway for shifting the paradigm from “experience-driven” to “data- and model-driven”. In the future, by deepening domain knowledge embedding, exploring the synergy between large-scale and small-scale models, constructing human-machine collaborative platforms, and refining security frameworks, the intelligentization of natural gas exploration and development will be vigorously promoted, offering technical support for ensuring national energy security.
The successful development of the Sulige Gasfield has made a tremendous contribution to the continuously increasing tight gas production in the Ordos Basin. Currently, the central area of the gasfield has entered the middle-late stage of development, with both recovery factor and producing reserves reaching high levels. It is necessary to quantitatively characterize the spatial distribution of remaining reserves in tight sandstone reservoirs at this stage, and customize differentiated potential tapping strategies. In this paper, taking Block Su 36-11 in the central Sulige Gasfield as an example, the distribution of tight sandstone reservoirs was finely described. On this basis, a research method integrating three-dimensional geological modeling with CMOST intelligent history matching numerical simulation was adopted to calculate the development scale and distribution frequency of effective sand bodies, and describe the remaining tight gas reserves in a stepwise manner. The following results are obtained. (i) During the sedimentary period of Block Su 36-11, the hydrodynamic forces were strong. Sand bodies were extensively and continuously developed under the control of superimposed zones of braided rivers. (ii) The development frequencies of effective sand bodies in the eighth member of the Permian Lower Shihezi Formation (He 8 Member) and the first member of the Permian Shanxi Formation (Shan 1 Member) are relatively high, with the frequencies of 14%, 56%, and 30% for the upper and lower submembers of He 8 Member, and Shan 1 Member, respectively. (iii) The adopted CMOST module of CMG software enables automatic history matching and parameter optimization for gas wells. The quantitative evaluation results from numerical simulation indicate that the remaining gas is concentrated in the lower submember of He 8 Member and the second sublayer of Shan 1 Member, and it primarily occurs as interlayer remained gas and inter-well remained gas, and incomplete fracturing remained gas locally. (iv) For twenty-one well areas under four categories divided by reserve producing degree in the block, production strategies are researched separately depending on types of well areas. It is concluded that differentiated potential tapping strategies, such as local well pattern infilling, reperforation, old well sidetracking, and overall deployment, should be implemented according to the specific types of well areas to enhance the gas recovery of the block and thus contribute to the sustaining stable production in the Sulige Gasfield.
There exists complexities in productivity and its decline laws in the depletion development of deep carbonate gas reservoirs with strong heterogeneity caused by reservoir type differences. Taking the deep carbonate gas reservoirs in the Sichuan Basin as the research subject, physical simulation experiments of depletion development were conducted on cores with different physical property ranges and reservoir types, under the conditions of formation temperature and pressure. The dynamic variations in parameters such as instantaneous gas production rate, pore pressure, and recovery factor were revealed through these experiments. The gas productivity, production cycle, and producing reserves were analyzed for each reservoir type, and the impacts of vugs and fractures on depletion development performance were elucidated. The following results are obtained. (i) Permeability governs the upper limit of productivity in depletion development, while porosity affects the duration of high production. (ii) Reservoirs with high permeability and low porosity can achieve high recovery factor in the short term, whereas low-permeability, high-porosity reservoirs exhibit lower recovery factor and extended production cycles. (iii) The reasonable combination of fractures and vugs is crucial to high and stable production, while vugs primarily enhance the reservoir space with minimal impact on flow capacity. (iv) Fractured-vuggy reservoirs demonstrate high recovery factor and can produce at high rates in a short period. Vuggy reservoirs exhibit slightly higher recovery factor than porous reservoirs and can sustain lower, stable production rates over a long period. In contrast, porous reservoirs yield the lowest recovery factor and struggle to achieve cost-effective production. It is concluded that the depletion development of deep carbonate gas reservoirs is controlled by the pore-fracture-vug combination. Specifically, fractured-vuggy reservoirs demonstrate strong short-term and long-term productivity, staying as the major contributor to profitable development; vuggy reservoirs require acid stimulation to improve the flow capacity, thereby achieving the beneficial production; and porous reservoirs are not promising for reserve producing and can be considered for regional energy replenishment.
During the development process, water-bearing gas reservoirs may suffer water influx, leading to reduced gas well productivity or even well shutdown, significantly lowering the reservoir's recovery rate. To provide reference for subsequent studies and engineering applications, this paper systematically investigates the research advances of existing water influx characterization methods. According to literature review and technology comparison, this paper critically evaluates the applicability and limitations of hydrochemical analysis, production performance diagnosis, pressure response interpretation, development logging and testing techniques, and data-driven methods in identifying water influx types, assessing aquifer activity, and tracing water influx pathways. The findings indicate that: (i) hydrochemical analysis effectively distinguishes different water sources but suffers from response lag; (ii) the production dynamic analysis method is simple and intuitive, but it is difficult to quantitatively characterize the intensity of water invasion; (iii) pressure response interpretation enables dynamic monitoring and quantitative assessment of water influx impacts, though some models fail to adequately account for mechanisms such as water-blocking gas; (iv) development logging and testing techniques offer high resolution and strong specificity but entail high operational costs; and (v) data-driven method demonstrates strong potential in forecasting water production trends, although their performance is highly dependent on data quality and computational resources. It is concluded that due to the inherent limitations of individual methods, an integrated multi-method approach is essential in practice to enhance the accuracy and reliability of water influx identification and evaluation. Future efforts should focus on developing an early-warning system for water influx that synergistically combines physical constraints with data-driven techniques, thereby shifting from reactive, lagging responses to proactive, early-stage prevention and control.
To achieve a coordinated regulation of efficient development, balanced recovery, and water influx control in thick heterogeneous gas reservoirs, this study conducts a comprehensive literature review on research methods for interference flow mechanisms, water influx patterns, and water control techniques. Also, the development directions of these research methods were predicted and analyzed. Results show that: (i) traditional physical simulation methods are limited in scale and heterogeneity representation, and yield physical field characterizations with insufficient accuracy, making it difficult to reflect the spatial distribution of physical fields and the characteristics of interference flow during thick-layer reservoir development; (ii) fluid migration in thick-layer reservoirs is jointly affected by heterogeneity and multiple seepage effects. Conventional theories fail to couple multi-directional heterogeneity with nonlinear flow behavior, leading to distorted representations of the flow process; (iii) reserves mobilization and water control in thick-layer reservoirs are mutually restrictive and coupled. Single-objective numerical simulation methods cannot quantitatively describe their interaction and rationally determine the optimal balance between them; (iv) research tools will evolve toward large-scale physical models with high similarity and refined visualization of physical fields, coupled mathematical models for bidirectional heterogeneity, multifield interaction, and multiphase flow, intelligent numerical simulation platforms integrating physical constraints and deep learning, and collaborative decision-making systems for balanced development and water influx regulation. The conclusion is that the reserves mobilization and stable water control in thick heterogeneous gas reservoirs are mutually constrained and coupled. Quantifying the collaborative mechanism between the two and constructing a multi-dimensional collaborative optimization method are the future research directions for balanced water control development under reasonable pressure control in this type of gas reservoir.
The gas fields in the Kuqa piedmont of the Tarim Basin consist of a series ultra-deep fractured tight sandstone edge-water gas reservoirs, featuring multi-scale discrete fractures including matrix-fracture-fault systems, which pose great challenges to well test interpretation. Based on actual test data and the basic principles of well test interpretation, this paper systematically analyzes the characteristics of well test type curves for fractured water-bearing gas reservoirs in the Kuqa piedmont. Results show that: (i) for edge gas wells, the late-stage upward warping of the pressure derivative may be a false boundary formed by the viscosity difference between gas and water, and the pressure derivative curve generally shrinks to the upper left in the log-log plot with the gradual advancement of water; (ii) the late-stage pressure derivative presents a straight line with a slope between 0.5 and 1 for gas wells at high structural positions. The slope value reflects the development degree of fracture networks. The more complex the fracture network, the larger the slope. The slope of the pressure derivative curve changes before and after water breakthrough in the wells at high structural positions, and resumes to the original state after complete water flooding; (iii) comparison of well test pressure derivative curves normalized using production data of a single well at different stages indicates no significant change in formation coefficient without edge water influence; (iv) there exists gas supply from matrix to fracture system. To sum up, for the fractured gas reservoirs with tight matrix in the field group in the Kuqa piedmont, their key parameters such as permeability and storativity ratio cannot be interpreted using analytical well test methods when the total system radial flow does not appear on the derivative curve. The late-stage upward warping of the pressure derivative curves for gas wells at edge is not necessarily a boundary characteristic, and this phenomenon should be analyzed combining dynamic and static data. During the development process, the reservoir permeability does not show obvious stress sensitivity characteristics.
There exists the challenges of frequent frac-hits and varying frac-hit patterns caused by tight reservoir rocks and abnormally developed natural fracture zones, and the lack of targeted anti-frac-hit technologies during hydraulic fracturing of deep shale gas wells in the southern Sichuan Basin. To address these challenges and thus improve reservoir stimulation, a frac-hit fracture propagation model for horizontal wells in deep shale gas reservoirs was constructed using a method integrating numerical simulation and theoretical analysis. Based on three frac-hit patterns, the effectiveness of four anti-frac-hit technologies were investigated and compared under varying frac-hit degrees. The following results are obtained. (i) Three evaluation indices relating to the constructed model, namely stress front radius, fracture asymmetric growth coefficient (AGC), and pressure change integral (PCI) index, are conducive to the multi-dimensional quantitative characterization of frac-hit degree. Specifically, the stress front radius reflects the scope of in-situ stress disturbance, the fracture AGC quantifies the asymmetry in fracture propagation, and the PCI index characterizes the abnormality in the wellhead pressure field. The three indices jointly form a comprehensive frac-hit evaluation system. (ii) The W-shaped well placement technology shows strong pertinence, offering optimal prevention and control against two frac-hit patterns: natural fracture-mediated interference (Type Ⅱ) and direct hydraulic fracture-mediated interference (Type Ⅲ), by effectively blocking the formation and extension of frac-hit channels. (iii) Alternate well zipper fracturing and stepwise drainage rate increase technologies are widely applicable, and can significantly control frac-hits for both pore-elastic interference mediated by rock matrix (Type Ⅰ) and natural fracture-mediated interference (Type Ⅱ) by regulating the stress field and fracture propagation direction. (iv) The technology of diversion while pump shutdown combined with high-concentration proppant injection in pad stage is suitable for the Type Ⅰ and small-scale Type Ⅱ, inhibiting interference impacts by optimizing fracture morphology. In conclusion, this study clarifies the application scenarios and regulation mechanisms of different anti-frac-hit technologies, and proposes the applicable schemes of the technologies, providing technical support for frac-hit prevention and control during pre-production fracturing operations of deep shale gas horizontal wells in the southern Sichuan Basin.
In order to systematically review the development trajectory of coal-rock reservoir damage evaluation methods, and address the challenges in selecting appropriate damage prevention and control methods due to fragmented information, dissection and trend modeling were conducted on relevant literatures published during 1982-2023 through a research approach integrating bibliometric and time-series analyses. The following results are obtained. (i) For the constructed model of changing volume of literature over time, the determination coefficients of equations for the 3-year and 6-year observation periods are 0.755 5 and 0.799 4, respectively, indicating a satisfactory fitting of medium- and long-term trends. The equations can be used to reveal the overall development pattern of coal-rock reservoir damage evaluation methods. In contrast, the equation corresponding to 1-year observation period is significantly affected by short-term fluctuations and thus provides a limited interpretability. (ii) The trend fitting for physical and digital evaluation methods shows that both methods exhibit positive correlation between the volume of literature and time for 3-year and 6-year periods. The determination coefficients of the physical method are 0.756 9 and 0.840 1, respectively, while those of the digital method are 0.582 0 and 0.677 8, respectively, indicating that the physical method evolves in a more stable and remarkable trend. (iii) In view of growth trend, the physical and digital methods are similar in the literature volume in the early stage; however, according to the fitting for 3-year and 6-year periods, the physical method reflects growth slopes (1.156 0 and 4.607 1) much higher than those (0.107 7 and 0.428 6) of the digital method, implying that the physical method is dominant and maintains a fast development. It is concluded that the physical method will remain the key evaluation option for a long time in the future. Issues such as sample limitation and prolonged evaluation period associated with the method can be addressed by the integration with the digital method. The integrated physical-digital method for coal-rock reservoir damage evaluation is expected to provide a powerful support for accelerating exploration and development of coalbed methane.
Accurate identification and characterization of reservoir-seepage units (RSUs) can reveal the matching relation between static geological elements and production dynamic characteristics, and thus improve the development benefits of highly heterogeneous carbonate gas reservoirs in production plateau. Therefore, this study investigated the gas reservoir in the fourth member of the Upper Sinian Dengying Formation (Deng-4 Member) in the platform-margin belt of the GM block, Anyue Gasfield, Sichuan Basin. Guided by the concept combining production dynamic characteristics and static geological understanding (dynamic-static combination for short), the RSUs were finely characterized, and the development flow units (DFUs) were thoroughly analyzed, based on the identification and classification of RSUs, as well as seismic, geological, and production data. Furthermore, the remaining producible reserves in different DFUs in the study area were systematically evaluated. The following research findings are obtained. (i) Three types of RSUs are identified: Type Ⅰ, dominated by fractured-vuggy reservoirs with high flow conductivity; Type Ⅱ, primarily composed of vuggy reservoirs with pore-throat structure; and Type Ⅲ, mainly consisting of isolated porous reservoirs. Types Ⅰ to Ⅲ rank in a descending order of reservoir and flow capacity, and Types Ⅰ and Ⅱ are defined as high-quality RSUs. (ii) High-quality RSUs show remarkable heterogeneity of spatial distribution, and their development scale is a key geological determinant for high and stable production of gas wells. (iii) The study area is divided into four Type Ⅰ, one Type Ⅱ, and two Type Ⅲ DFUs, according to the characteristics and dynamic responses of RSUs. The remaining producible reserves are mainly enriched in the Type Ⅱ and Ⅲ DFUs. It is concluded that, the differentiated development strategy based on “categorized optimization and targeted measures” is an effective option to address the geological element and production performance complexities in highly heterogeneous gas reservoirs; the closed-loop research approach incorporating update of geological models, integration of engineering technologies, and continuous optimization of dynamic-static combination is crucial to ensure efficient development of such reservoirs.
The Changning shale gas field serves as a cornerstone for sustained increase of shale gas production in southern Sichuan Basin. However, its geological engineering conditions are more complex than those of North America. Also, the Changning shale gas filed is characterized by strong reservoir heterogeneity and rapid production decline, resulting in a reserves recovery of only 20%-30% by development with primary well pattern. This uneven and insufficient mobilization of reserves has posed significant challenges to stable production. Based on detailed reservoir characterization, an innovative enhanced gas recovery (EGR) technology based on secondary well pattern was developed by incorporating some key techniques such as four-dimensional (4D) in-situ stress characterization, full-field numerical simulation, and well pattern-fracture network collaborative optimization. This led to the innovative formation of a secondary well pattern-based EGR technology for shale gas reservoirs to enhance recovery factors. Subsequently, the target areas for remaining shale gas reserves in the field were selected, and optimized deployment of infill wells and three-dimensional development wells was implemented. The research findings indicate that the proposed secondary well pattern-based EGR technology, centered on the fine reconstruction of 3D model, pressure field, stress field, estimated ultimate recovery (EUR) of well groups, and spatial well pattern, enables a well pattern-fracture network collaboration to improve the recovery within the three-dimensional space. Field test results demonstrate that well infilling and three-dimensional development increase the platform recovery by 40%-60% compared to the primary well pattern. By meticulously characterizing the distribution of remaining shale gas reserves in the Changning block, a target area of 298.6 km2 was selected for employing the secondary well pattern, where additional 246 infill and three-dimensional development wells were deployed with expected recovery enhancement by 27%. This study provides valuable guidance for enhancing both reserves mobilization and EUR of shale gas reservoirs in the Sichuan Basin.
Stable production of deep reef-shoal high-sulfur gas reservoirs is dependent on key factors such as water invasion, sulfur deposition, and remaining gas potential tapping. Considering these factors, and through fine characterization of reef-shoal reservoirs, this paper researches the identification and prediction of water invasion front, prediction of sulfur deposition, and fine characterization of remaining gas, and proposes specific solutions to water control, sulfur control, and remaining gas potential tapping. The following results are obtained. (i) The established fine characterization and dual-medium modeling technologies for deep reef-shoal reservoirs enable the fine characterization of strongly heterogeneous reef-shoal reservoirs and evaluation of classified reserves, laying the foundation for prediction of water invasion and sulfur deposition, and fine characterization of remaining gas. (ii) The developed logging-seismic-electric technology for identifying water invasion front allows for three-dimensional identification of gas-water front. And the water control strategy of “control-drainage-plugging” is customized depending on types of gas wells. (iii) The formed technology for predicting wellbore and reservoir sulfur deposition clarifies the sulfur deposition patterns in wellbores and reservoirs, and explores the microscopic flow behaviors of solid and liquid sulfur in reservoirs. Countermeasures for wellbore sulfur deposition are proposed, with acidizing plug removal confirmed as the optimal one. (iv) The developed fine characterization technology for remaining gas based on differences in seepage characteristics in different zones quantitatively describes remaining gas distribution in gas zones and water invasion zones. The types of remaining gas are categorized, thereby solutions to classified potential tapping are proposed. It is concluded that these technologies can effectively address the challenges of stable production faced by deep reef-shoal high-sulfur gas reservoirs, providing a valuable reference for achieving long-term and efficient development of similar gas reservoirs.
Deep carbonate gas reservoirs are generally characterized by large burial depth, strong heterogeneity, and complex gas-water relationship, leading to high investment risks and development challenges. Traditional evaluation methods fail to distinguish the influences of subjective and objective factors on the development effect of these gas reservoirs. In order to accurately identify the main factors controlling the development effect and provide a scientific basis for optimized development of similar reservoirs, a multidimensional evaluation indicator system integrating technical, economic, and development-level aspects was constructed by introducing an indicator of “development level” based on the conventional technical and economic indicators, and quantifying the contribution of human factors. The following results are obtained. (i) The proposed evaluation method can effectively separate objective geological factors from subjective human factors. Its application to the Carboniferous gas reservoirs in eastern Sichuan Basin demonstrates high development-level indexes (80%-97%) and significant variation in development-effect indexes (50%-91%), suggesting the fundamental control of geological conditions. (ii) Reservoir quality, driving type, and compatibility between development mode and reservoir heterogeneity are identified as the three main factors influencing the development effect of the gas reservoirs. (iii) For gas reservoirs developed in early stage with balanced development mode, the development effect is significantly and positively correlated to formation flow capacity and reserves abundance; for gas reservoirs following the “few wells, high production” mode, water invasion is the core risk, and the development effect deteriorates notably with increasing intensity of water invasion; and for gas reservoirs with strong heterogeneity, effective production of reserves must rely on the development mode of “basic well pattern+ multi-round well infilling”. In conclusion, by quantifying the contributions of various factors (especially human factors), the main factors influencing development are effectively identified, providing a valuable support to the optimization of development strategies and management decisions for deep carbonate gas reservoirs.
Taking the Bozhong19-6 gasfield in the Bohai Bay Basin as an example, a systematic evaluation was conducted for injector-producer connectivity during gas-drive development in deep buried-hill condensate gasfields, using a method integrating static and dynamic researches, together with core CT scans, imaging logs, and production performance data. Through the static research, the microscopic structure and macroscopic distribution patterns of the fracture network were clarified, based on the topological fracture average connection number theory. Through the dynamic research, a dynamic connectivity diagnosis method centered on productivity index (PI) superposition was established, according to the Blasingame pseudo-steady-state flow theory for variable-rate and variable-flow-pressure gas wells. The following research results are obtained. (i) The target reservoirs generally exhibit critical to weak connectivity patterns characterized by large-scale discrete fractures and small- to medium-scale connected fractures, with an average fracture connection number ranging from 1.1 to 2.8. The verification by incorporating both static and dynamic researches shows strong connectivity among Wells A2, A4H, and A7. (ii) Based on fracture density, fracture opening, and connectivity parameters, a multi-scale discrete fracture model considering connectivity (EDFM+PGT) is constructed. Compared with conventional dual-medium models, this new model yields a significantly improved accuracy in predicting the gas-drive development performance. (iii) Field application of a balanced injection-production strategy involving production limitation and injection enhancement, guided by the connectivity evaluation, enables the target well group to demonstrate positive gas-drive response characteristics. It achieves zero decline in condensate production and zero increase in gas-oil ratio, effectively controlling retrograde condensation. It is concluded that the proposed approach incorporating both static and dynamic researches for connectivity evaluation can effectively quantify inter-well connectivity in complex fractured buried-hill condensate gas reservoirs, providing scientific evidences for optimization and dynamic regulation of gas-drive development plans. It can be referential for efficient development of similar reservoirs.
The Yuanba Gasfield, located in the northeastern Sichuan Basin, is the first ultra-deep, high-sulfur organic reef gasfield with a buried depth reaching 7 000 m among the world’s developed gasfields. However, it is characterized by high temperature, high pressure, high sulfur content, strong reservoir heterogeneity, and complex gas-water relationship, making its development extremely challenging. Through over a decade of technical research and development practices, the Yuanba Gasfield has efficiently established a purified gas output of 34×108 m3/a and achieved a stable production for 10 consecutive years. This paper systematically reviews the development practices throughout the entire process from evaluation to stable production of the Upper Permian Changxing Formation gas reservoirs in the Yuanba Gasfield, and summarizes the innovations in development management model and their implications for future operations. The following results are obtained. (i) The precision identification, fine characterization, and thin reservoir quantitative prediction technologies for ultra-deep, multi-stage, ribbon-shaped small reefs enable the classfication forecasting of Type Ⅰ to Ⅲ reservoirs with buried depth of 7 000 m and minimum thicknesses of 15 m. (ii) The efficient development technology for ultra-deep scattered resources, which innovatively integrates ultra-deep horizontal well design optimization, optimal and fast drilling and trajectory control, and multistage temporary plugging and acid stimulation for long horizontal sections, allows for effective recovery of ultra-deep high-sulfur gas reservoirs with bottom water. (iii) The full lifecycle differentiated water control technology for bioherm bottom-water gas reservoirs and the efficient treatment technology for abnormal wells in ultra-deep high-sulfur gas reservoirs effectively break through the bottlenecks such as water invasion and blockage impeding long-term stable production, thereby securing the plateau period of the gasfield. (iv) The supporting technologies including efficient producing of different types of remaining gas, pressurization for non-integral sour gas reservoirs, and comprehensive treatment of sulfur deposits and formation water contribute to the enhanced gas recovery. It is concluded that an efficient development model for the Yuanba Gasfield has been established, characterized by spiritualized inheritance, collectivized decision-making, projectized management, and integrated innovation, enhancing China’s technical leadership in the sector of ultra-deep high-sulfur gasfield development. Its management model and technical achievements can provide references for similar gas fields.
Precise potential tapping of remaining gas is conducive to enhanced gas recovery of water-invaded unconsolidated sandstone gas reservoirs. Taking the Sebei Gasfield of the Qaidam Basin as an example, this study integrates laboratory experiments, gas reservoir engineering theories and field practices to analyze the key factors controlling the remaining gas distribution in water-invaded areas. Moreover, a quantitative identification method for remaining gas potential areas is proposed, and the classification and evaluation criteria are established. The following results are obtained. (i) The distribution of remaining gas in unconsolidated sandstone reservoirs of the Sebei Gasfield is jointly controlled by microscopic factors (e.g. pore structure, clay mineral composition, water sensitivity, and pressure sensitivity) and macroscopic factors (e.g. heterogeneity, structural location, reservoir pressure drop, and well-pattern control). (ii) The proposed “2221” quantitative identification method for remaining gas potential areas in water-invaded reservoirs comprehensively considers seven parameters including reserves, seepage, water invasion status, and stable production capacity. (iii) The established 5-parameter classification and quantitative evaluation criteria categorize the potential areas into three types: high-abundance remaining gas, medium-abundance water-sealed gas, and low-abundance residual gas areas. Targeted potential-tapping strategies for each type are proposed. The research findings have proven to be convenient and practical in field applications, enabling a shift from “qualitative description” to “quantitative definition” of remaining gas potential areas. The proposed technology system featuring precise identification, classified evaluation, and targeted strategies has performed effectively in enhancing recovery of mature gasfields, and offer a reference for improving recovery in similar gas reservoirs with water.
In the middle-late stage of development, the Sebei Gasfield of the Qaidam Basin generally faces challenges such as low formation pressure, formation water invasion, low single-well productivity, and rapid production decline, which limit further enhancement of ultimate recovery factor. To address these challenges, a technical feasibility research on nitrogen injection for enhanced gas recovery (N2-EGR) was conducted systematically by adopting a comprehensive approach integrating laboratory experiments, numerical simulation, and field pilot tests. The following results are obtained. (i) Gas injection for EGR mainly involves three mechanisms: pressurization for energy replenishment (i.e. raising formation pressure to replenish reservoir energy), displacement, and diffusion. (ii) Laboratory experiments and numerical simulation have demonstrated that the best N2-EGR effect can be achieved when nitrogen is injected into reservoirs of Sebei Gasfield with recovery factor ranging 40%-50%, using a well pattern consisting of four injectors and six producers, with an injection-production ratio maintained within 1.0-1.3. (iii) The pilot test of N2 injection in Layer A of the Sebei-1 Gasfield has shown preliminary effectiveness. The monitoring well S4-54 revealed remarkable stimulation effects, with its gas production increasing from 0.30×104 m3 before N2 injection to a peak of 1.24×104 m3 after injection. Meanwhile, the formation pressure in the area of injection wells restored with an increase of 18% from 5.99 MPa to 7.09 MPa, indicating effective energy replenishment. In conclusion, the research findings confirm the feasibility of N2-EGR in the Sebei Gasfield, providing both theoretical foundation and technical support for subsequent expanded N2-EGR tests, as well as referable solution and practical basis for EGR of similar gas reservoirs.
