Natural Gas Industry B最新文献

{"title":"Numerical assessment of gas production potential via depressurization: Impact of production interval and bottom hole pressure at site NGHP-01-10D of the Krishna-Godavari Basin hydrate reservoir","authors":"Shadman Hasan Khan ,&nbsp;Monika Gandhi ,&nbsp;Beatrice Castellani ,&nbsp;Pietro Di Profio ,&nbsp;Michele Ciulla ,&nbsp;Amit Arora ,&nbsp;C.B. Majumder","doi":"10.1016/j.ngib.2025.06.003","DOIUrl":"10.1016/j.ngib.2025.06.003","url":null,"abstract":"<div><div>The National Gas Hydrate Program expeditions (NGHP-01 and -02) have conclusively proven the presence of hydrate deposits on the eastern coast of India. The novelty of the present study lies in its investigation of the richest gas hydrate deposit (hydrate saturation [Sh] &gt; 0.75), NGHP-01-10D, in the Krishna-Godavari (KG) Basin, India. The study presents a first look at the long-term gas production viability using a single vertical well, subjected to variations in production interval and bottom hole pressure. Specifically, we compared the gas production at bottom hole pressures of 3–6 MPa and production intervals of 20–40 m. The results indicate production rates that are technically feasible but lower than commercially acceptable standards. Increasing the bottom hole pressure drawdown from 6 MPa to 3 MPa increased the gas production from 1297 m³/d to 4902 m³/d (i.e., more than tripling the average daily gas production). Meanwhile, while expanding the production interval from 20 m to 40 m led to an increase in gas production, it also resulted in higher water production. As a result, the average gas-to-water ratio (R_GW) decreased from 9.5 to 5.3 with the expansion of the production interval, thereby highlighting the need to optimize the interval length. Furthermore, the spatial evolution of certain thermodynamic parameters, including pressure, temperature, and phase saturation (methane, water, and hydrate), underscores the critical role of heat transfer from the UB. Our study findings offer valuable insights for long-term production forecasting, the delineation of phase evolution patterns, and the identification of potential flow barriers that may impede deliverability.</div></div>","PeriodicalId":37116,"journal":{"name":"Natural Gas Industry B","volume":"12 4","pages":"Pages 482-500"},"PeriodicalIF":6.5,"publicationDate":"2025-08-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"144922816","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":3,"RegionCategory":"工程技术","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}

{"title":"Permeability evolution mechanism in deep coalbed methane extraction: Considering the competitive effects of adsorption-induced swelling, creep, and aperture compression","authors":"Yanhui Yang ,&nbsp;Tao Zhang ,&nbsp;Jianchun Guo ,&nbsp;Xiuqin Lu ,&nbsp;Zongyuan Li ,&nbsp;Jie Zeng ,&nbsp;Zhihong Zhao ,&nbsp;Yiqun Wang ,&nbsp;Dan Guo ,&nbsp;Jingwen Li","doi":"10.1016/j.ngib.2025.08.004","DOIUrl":"10.1016/j.ngib.2025.08.004","url":null,"abstract":"<div><div>During gas extraction from deep coal, the rock endures high effective stress, with both the time-dependent deformation and anisotropic structure of the rock controlling the permeability evolution. To reveal this phenomenon, a numerical simulation framework of the finite volume method and transient embedded discrete fracture model is proposed to establish a new constitutive model that links poroelastoplastic deformation, adsorption-induced swelling, and aperture compression. From this model, anisotropic permeability tensors were derived to further achieve the simulation of coevolution. Meanwhile, our permeability model was verified against the measured permeability data, and the history match of the numerical model showed better results where the mismatch was less than 5 %. The results indicate that (1) the long-term permeability evolution clearly showed the competitive effects of multiple deformation mechanisms, which involves three stages: compaction-dominated decline, adsorption-dominated rebound, and creep-controlled loss. (2) The increased number of compressible cleats/fractures accelerated the initial permeability decline, while the increased desorption-induced strain promoted faster rebound and enhancement and higher viscosity coefficients enhanced the creep effect, which led to significant long-term permeability loss. (3) Massive hydraulic fracturing created a larger drainage area, accelerating methane desorption and causing sharp permeability rebound with reduced residual gas, which shows that the permeability remained higher than the initial values even after the extensive extraction via the fractured horizontal wells. The permeability evolution mechanisms displayed varying properties, such as coal rank and burial depth, and distinct characteristics. A precise understanding of multiple competitive stress effects is crucial for optimizing coalbed methane extraction techniques and improving recovery efficiency.</div></div>","PeriodicalId":37116,"journal":{"name":"Natural Gas Industry B","volume":"12 4","pages":"Pages 416-431"},"PeriodicalIF":6.5,"publicationDate":"2025-08-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"144922801","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":3,"RegionCategory":"工程技术","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}

{"title":"Damage location prediction of cement-sandstone combinations under axial force: Three-dimensional structure reconstruction and stress distribution simulation based on μ-CT","authors":"Zhong Li ,&nbsp;Zhiming Yin ,&nbsp;Xingquan Zhang ,&nbsp;Tao Gu ,&nbsp;Fubin Xin ,&nbsp;Zhiqiang Huang","doi":"10.1016/j.ngib.2025.08.001","DOIUrl":"10.1016/j.ngib.2025.08.001","url":null,"abstract":"<div><div>Effective isolation between the cement sheath and the sandstone is crucial for the development and production of oil and gas wells in sandstone formations. In this study, a cement-sandstone composite (CSC) was prepared, and based on μ-CT three-dimensional reconstruction imaging and finite element analysis (FEA) techniques, the stress distribution and potential failure mechanism at the cement-sandstone bonding interface under axial loading were analyzed. The key findings are as follows: (1) stress concentrations are highly likely to form at the gap between the cement and sandstone interface and around interfacial voids, with Von Mises stress reaching critical levels of 18.0–20.0 MPa at these locations, significantly exceeding the stress magnitudes in well-bonded regions; (2) the phenomenon of local stress concentration driven by interfacial defects can be identified as the main basis for predicting damage location in interfacial debonding and continuous shear under axial load; (3) ensuring tight cementation at the cement-sandstone interface and minimizing interfacial voids are paramount for preventing stress-induced failure; (4) the critical Von Mises stress value of 20 MPa at the interface defect can be used as a benchmark for material selection and designed to ensure long-term integrity in oil and gas well applications subjected to similar axial loads. These findings contribute to a more accurate understanding of the failure mechanism of the cement-sandstone interface and to the precise design of material properties, thereby ensuring the long-term integrity of oil and gas well applications subjected to similar axial loads.</div></div>","PeriodicalId":37116,"journal":{"name":"Natural Gas Industry B","volume":"12 4","pages":"Pages 405-415"},"PeriodicalIF":6.5,"publicationDate":"2025-08-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"144922800","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":3,"RegionCategory":"工程技术","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}

{"title":"Reconstruction of the geothermal field of the Xihu Depression in the East China Sea Basin and its controlling effect on hydrocarbon generation and distribution","authors":"Hui Diao ,&nbsp;Qiwen Yao ,&nbsp;Wei Zou ,&nbsp;Wu Zhang ,&nbsp;Jian Chang","doi":"10.1016/j.ngib.2025.06.002","DOIUrl":"10.1016/j.ngib.2025.06.002","url":null,"abstract":"&lt;div&gt;&lt;div&gt;The Xihu Depression, situated in the northeastern East China Sea Basin, represents the most significant natural gas-producing region in Eastern China. An insufficient understanding of reservoir heterogeneity in petroleum geological conditions—particularly within structural zones beyond the well-explored Pinghu Slope and Ningbo Anticline Belt—has hindered comprehensive hydrocarbon exploration across the sag. Critical knowledge gaps persist in characterizing the geothermal field, reconstructing thermal evolution histories, and constraining hydrocarbon generation phases. These limitations directly impede systematic evaluations of basin selection criteria, reservoir delineation, and their dynamic relationships within petroleum systems. This study analyzes the present geothermal gradient at a unified depth (4000–5000 m), the geothermal heat flow, the geothermal temperature at a unified depth (3000–6000 m), and the plan distribution characteristics of the geothermal temperatures of the exploration strata in the key study area in the Xihu Depression—the Western Slope and the Central Anticlinal Belt. The research in this study is based on present bottom-hole temperature measurements and temperature data for testing for oil, using a one-dimensional steady-state heat conduction equation and the Bullard method. The results indicate that the present geothermal gradient in the Xihu Depression, between a unified depth of 4000 m and 5000 m, ranges from 16.7 °C/km to 44.6 °C/km, with an average of 30.6 °C/km. The present geothermal heat flow is between 32.23 mW/m&lt;sup&gt;2&lt;/sup&gt; and 90.13 mW/m&lt;sup&gt;2&lt;/sup&gt;, with an average of 52.03 mW/m&lt;sup&gt;2&lt;/sup&gt;, indicating a typical cold basin. The formation temperature gradually increases with burial depth, from 3000 m to 6000 m. In the plane, the formation temperature gradually increases from the south to the north and from the edge of the depression to the center of the depression. The burial history and thermal evolution of the key plays of the Xihu Depression were reconstructed using apatite fission tracks and zircon U–Th/He data, combined with vitrinite reflectance, which revealed that the tectonic uplift that occurred during the Late Miocene Longjing Movement was a critical event in trap formation and hydrocarbon filling. The thermal-hydrocarbon generation history indicates that the Xihu Depression has mostly entered a high maturity stage, with gas condensate and condensate charging occurring between 16.4 Ma and 13 Ma and natural gas filling occurring at 5.3 Ma up to now. Hydrocarbon generation and expulsion in the Xihu Depression occurred early in the north and late in the south, with two stages in the north and one stage in the south. A study of the burial history–thermal history–hydrocarbon generation history based on the reconstruction of geothermal fields demonstrates the matching relationship between hydrocarbon generation, distribution, and accumulation in the Xihu Depression—an understanding that is vital","PeriodicalId":37116,"journal":{"name":"Natural Gas Industry B","volume":"12 4","pages":"Pages 462-481"},"PeriodicalIF":6.5,"publicationDate":"2025-08-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"144922815","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":3,"RegionCategory":"工程技术","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}

{"title":"An iteration-free approach for determining the average reservoir pressure and original gas in place by production data analysis: Methodology and field cases","authors":"Yang Wang ,&nbsp;Shilong Yang ,&nbsp;Hang Xie ,&nbsp;Naichao Feng ,&nbsp;Haiyang Yu","doi":"10.1016/j.ngib.2025.05.006","DOIUrl":"10.1016/j.ngib.2025.05.006","url":null,"abstract":"<div><div>Current gas well decline analysis under boundary-dominated flow (BDF) is largely based on the Arps' empirical hyperbolic decline model and the analytical type curve tools associated with pseudo-functions. Due to the nonlinear flow behavior of natural gas, these analysis methods generally require iterative calculations. In this study, the dimensionless gas rate (<em>q</em>_g/<em>q</em>_gi) is introduced, and an explicit method to determine the average reservoir pressure and the original gas in place (OGIP) for a volumetric gas reservoir is proposed. We show that the dimensionless gas rate in the BDF is only the function of the gas PVT parameters and reservoir pressure. Step-by-step analysis procedures are presented that enable explicit and straightforward estimation of average reservoir pressure and OGIP by straight-line analysis. Compared with current techniques, this methodology avoids the iterative calculation of pseudo-time and pseudo-pressure functions, lowers the multiplicity of type curve analysis, and is applicable in different production situations (constant/variable gas flow rate, constant/variable bottom-hole pressure) with a broad range of applications and ease of use. Reservoir numerical simulation and field examples are thoroughly discussed to highlight the capabilities of the proposed approach.</div></div>","PeriodicalId":37116,"journal":{"name":"Natural Gas Industry B","volume":"12 3","pages":"Pages 328-338"},"PeriodicalIF":4.2,"publicationDate":"2025-06-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"144501784","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":3,"RegionCategory":"工程技术","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}

{"title":"Characteristics of shale reservoir development under the influence of sedimentary differentiation: A case study of the Cambrian Qiongzhusi Formation in the Deyang-Anyue rift trough of the Sichuan Basin","authors":"Wenyi Chen ,&nbsp;Bo Wang ,&nbsp;Zhenxue Jiang ,&nbsp;Dandan Wang ,&nbsp;Hui Long ,&nbsp;Wenlei Liu ,&nbsp;Dadong Liu","doi":"10.1016/j.ngib.2025.05.001","DOIUrl":"10.1016/j.ngib.2025.05.001","url":null,"abstract":"<div><div>The Cambrian Qiongzhusi Formation in the Sichuan Basin harbors significant potential for shale gas harvesting. However, systematic disparities in mineral composition and reservoir architecture have been observed between intra- and extra-trough reservoirs within the Deyang–Anyue Rift Trough. These variations were primarily determined by divergences in the sedimentary environments developed during the evolution of the rift trough, which were a main factor in fostering the heterogeneous distribution of shale gas enrichment found today. However, the genetic mechanisms that govern reservoir heterogeneity across distinct structural domains (intra-trough, trough margin, and extra-trough) remain poorly understood, particularly regarding the coupling relationships between depositional environments, reservoir characteristics, and gas-bearing properties. This study adopts a multidisciplinary approach to investigating this issue that integrates core analysis, well-log interpretations, and geochemical data. Through systematic comparisons conducted using X-ray diffraction mineralogy, organic carbon quantification, and spontaneous imbibition experiments, we characterize the mineral assemblages, organic geochemical signatures, and pore structures found across the three structural domains of the Deyang–Anyue Rift Trough. The key findings are as follows: (1) The depositional environment is the main influence on reservoir distribution and organic matter enrichment, with intra-trough shales exhibiting a higher abundance of organic matter than their trough-margin and extra-trough counterparts. (2) Enhanced brittleness in intra-trough zones correlates with the predominance of biogenic silica therein. (3) Synergistic organic-inorganic interactions govern pore system development. (4) Gas-bearing capacity is jointly determined by effective porosity and organic matter content. These findings establish the rift trough as a preferential exploration target, providing critical geological guidance for optimizing shale gas exploration strategies in the Cambrian Qiongzhusi Formation.</div></div>","PeriodicalId":37116,"journal":{"name":"Natural Gas Industry B","volume":"12 3","pages":"Pages 251-263"},"PeriodicalIF":4.2,"publicationDate":"2025-06-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"144502416","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":3,"RegionCategory":"工程技术","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}

{"title":"A technical review of chemical reactions during CCUS-EOR in different reservoirs","authors":"Ali Satea ,&nbsp;Ye Tian ,&nbsp;Zuhao Kou ,&nbsp;Bo Kang ,&nbsp;Yulong Zhao ,&nbsp;Liehui Zhang","doi":"10.1016/j.ngib.2025.05.002","DOIUrl":"10.1016/j.ngib.2025.05.002","url":null,"abstract":"<div><div>Geochemical reactions play a vital role in determining the efficiency of carbon capture, utilization, and storage combined with enhanced oil recovery (CCUS-EOR), particularly through their influence on reservoir properties. To deepen the understanding of these mechanisms, this review investigates the interactions among injected CO₂, formation fluids, and rock minerals and evaluates their implications for CCUS-EOR performance. The main results are summarized as follows. First, temperature, pressure, pH, and fluid composition are identified as key factors influencing mineral dissolution and precipitation, which in turn affect porosity, permeability, and CO₂ storage. Second, carbonate minerals, such as calcite and dolomite, show high reactivity under lower temperature conditions, enhancing dissolution and permeability, while silicate minerals, including illite, kaolinite, quartz, and K-feldspar, are comparatively inert. Third, the formation of carbonic acid during CO₂ injection promotes dissolution, whereas secondary precipitation, especially of clay minerals, can reduce pore connectivity and limit flow paths. Fourth, mineral transformation and salt precipitation can further modify reservoir characteristics, influencing both oil recovery and long-term CO₂ trapping. Fifth, advanced experimental tools, such as Computed Tomography (CT) and Nuclear Magnetic Resonance (NMR) imaging, combined with geochemical modeling and reservoir simulation, are essential to predict petrophysical changes across scales. This review provides a theoretical foundation for integrating geochemical processes into CCUS-EOR design, offering technical support for field application and guiding sustainable CO₂ management in oil reservoirs.</div></div>","PeriodicalId":37116,"journal":{"name":"Natural Gas Industry B","volume":"12 3","pages":"Pages 264-278"},"PeriodicalIF":4.2,"publicationDate":"2025-06-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"144501779","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":3,"RegionCategory":"工程技术","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}

{"title":"Study on influences of geological and gas source conditions on gas-chimney hydrate accumulation using a reservoir numerical simulation method","authors":"Liang Zhang ,&nbsp;Fuyang Li ,&nbsp;Lu Yu ,&nbsp;Songhe Geng ,&nbsp;Chunjie Li ,&nbsp;Yujie Sun","doi":"10.1016/j.ngib.2025.05.003","DOIUrl":"10.1016/j.ngib.2025.05.003","url":null,"abstract":"<div><div>The Shenhu Area in the South China Sea is rich in oil and gas resources and has many vertical gas chimneys, making it an excellent geological environment for hydrate accumulation. This paper examines the geological conditions governing these gas-chimneys. A numerical simulation method based on the partial-equilibrium reaction model of hydrate was applied to simulate the migration of methane gas and the resultant hydrate formation when the gas enters the hydrate stability zone under the seabed through gas-chimneys. The dynamics of this gas-chimney hydrate accumulation were analyzed, and the influences of different factors—namely, the fluid supply time, rate, and temperature—on the formation temperature and ultimate distribution of the hydrate reservoir were evaluated. The simulation results indicate that the accumulation of hydrate via gas-chimneys is significantly affected by the temperature of the gas source, the transfer state of the methane gas, and the number of cycles of alternating gas–water invasion. Hydrate accumulation takes shape in an annular or semi-annular distribution pattern divided by fluid state as follows: a two-phase gas–water zone, a three-phase gas–water–hydrate zone, a two-phase water–hydrate zone, and a phase of water passing from the inside to the outside. Formation inclination and reservoir heterogeneity can greatly affect the distribution shape and abundance of the hydrate. A high fluid supply temperature, frequent alternating invasions of gas and water, and long-term pore-water invasion at a high rate can jointly cause a large central hydrate-free zone. In contrast, a long-term supply shutdown during the alternating gas–water invasion process, and a high gas rate with a low water rate in the gas-dominant invasion stage, foster the accumulation of hydrate in great abundance and with considerable thickness. The results of this study can help us understand the accumulation of hydrate through gas chimneys in the Shenhu Area.</div></div>","PeriodicalId":37116,"journal":{"name":"Natural Gas Industry B","volume":"12 3","pages":"Pages 279-297"},"PeriodicalIF":4.2,"publicationDate":"2025-06-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"144501780","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":3,"RegionCategory":"工程技术","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}

{"title":"Gas occurrence characteristics in marine-continental transitional shale from Shan23 sub-member shale in the Ordos Basin: Implications for shale gas production","authors":"Guangyin Cai ,&nbsp;Yifan Gu ,&nbsp;Dongjun Song ,&nbsp;Yuqiang Jiang ,&nbsp;Yonghong Fu ,&nbsp;Ying Liu ,&nbsp;Fan Zhang ,&nbsp;Jiaxun Lu ,&nbsp;Zhen Qiu","doi":"10.1016/j.ngib.2025.05.009","DOIUrl":"10.1016/j.ngib.2025.05.009","url":null,"abstract":"<div><div>Pore structure characteristics, gas content, and micro-scale gas occurrence mechanisms were investigated in the Shan₂³ sub-member marine-continental transitional shale of the southeastern margin of the Ordos Basin using scanning electron microscope images, low-temperature N₂/CO₂ adsorption and high-pressure mercury intrusion, methane isothermal adsorption experiments, and CH₄-saturated nuclear magnetic resonance (NMR). Two distinct shale types were identified: organic pore-rich shale (Type OP) and microfracture-rich shale (Type M). The Type OP shale exhibited relatively well-developed organic matter pores, while the Type M shale was primarily characterized by a high degree of microfracture development. An experimental method combining methane isothermal adsorption on crushed samples and CH₄-saturated NMR of plug samples was proposed to determine the adsorbed gas, free gas, and total gas content under high temperature and pressure conditions. There were four main research findings. (1) Marine-continental transitional shale exhibited substantial total gas content in situ, ranging from 2.58 to 5.73 cm³/g, with an average of 4.35 cm³/g. The adsorbed gas primarily resided in organic matter pores through micropore filling and multilayer adsorption, followed by multilayer adsorption in clay pores. (2) The changes in adsorbed and free pore volumes can be divided into four stages. Pores of &lt;5 nm exclusively contain adsorbed gas, while those of 5–20 nm have a high proportion of adsorbed gas alongside free gas. Pores ranging from 20 to 100 nm have a high proportion of free gas and few adsorbed gas, while pores of &gt;100 nm and microfractures are almost predominantly free gas. (3) The proportion of adsorbed gas in Type OP shale exceeds that in Type M, reaching 66 %. (4) Methane adsorbed in Type OP shale demonstrates greater desorption capability, suggesting a potential for enhanced stable production, which finds support in existing production well data. However, it must be emphasized that high-gas-bearing intervals in both types present valuable opportunities for exploration and development. These data may support future model validations and enhance confidence in exploring and developing marine-continental transitional shale gas.</div></div>","PeriodicalId":37116,"journal":{"name":"Natural Gas Industry B","volume":"12 3","pages":"Pages 368-385"},"PeriodicalIF":4.2,"publicationDate":"2025-06-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"144501787","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":3,"RegionCategory":"工程技术","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}

{"title":"Integrated wellbore-surface pressure control production optimization for shale gas wells","authors":"Xingyu Zhou ,&nbsp;Liming Zhang ,&nbsp;Ji Qi ,&nbsp;Yanxing Wang ,&nbsp;Kai Zhang ,&nbsp;Ruijia Zhang ,&nbsp;Yaqi Sun","doi":"10.1016/j.ngib.2025.03.011","DOIUrl":"10.1016/j.ngib.2025.03.011","url":null,"abstract":"<div><div>Shale gas wells often face challenges in maintaining continuous and stable production due to their coexistence with high- and low-pressure wells within the same development block, which leads to issues involving mixed-pressure flows. Traditional pipeline optimization methods used in conventional gas well blocks fail to address the unique needs of shale gas wells, such as the precise planning of airflow paths, pressure distribution, and compression. This study proposes a pressure-controlled production optimization strategy specifically designed for shale gas wells operating under mixed-pressure flow conditions. The strategy aims to improve production stability and optimize system efficiency. The decline in production and pressure for individual wells over time is forecasted using a predictive model that accounts for key factors of system optimization, such as reservoir depletion, wellbore conditions, and equipment performance. Additionally, the model predicts the timing and impact of liquid loading, which can significantly affect production. The optimization process involves analyzing the existing gathering pipeline network to determine the most efficient flow directions and compression strategies based on these predictions, while the strategy involves adjusting compressor settings, optimizing flow rates, and planning pressure distribution across the network to maximize productivity while maintaining system stability. By implementing these strategies, this study significantly improves gas well productivity and enhances the adaptability and efficiency of the gathering and transportation system. The proposed approach provides systematic technical solutions and practical guidance for the efficient development and stable production of shale gas fields, ensuring more robust and sustainable pipeline operations.</div></div>","PeriodicalId":37116,"journal":{"name":"Natural Gas Industry B","volume":"12 2","pages":"Pages 123-134"},"PeriodicalIF":4.2,"publicationDate":"2025-04-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"143886561","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":3,"RegionCategory":"工程技术","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}