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During the development of multi-layer tight sandstone gas reservoirs in Ordos Basin, China, it has not been easy to calculate accurately the production of each individual layer in gas wells. However, production allocation provides a vital basis for evaluating dynamic reserves and drainage areas of gas wells and remaining gas distributions of gas layers. To improve the accuracy and reliability of production allocation of gas wells, a new model was constructed based on the seepage equation, material balance equation, and pipe string pressure equation. In particular, this new model introduced the seepage equation with an elliptical boundary to accurately capture the fluid flow characteristics within a lenticular tight gas reservoir. The new model can accurately calculate the production and reservoir pressure of each individual layer in gas wells. In addition, the new model was validated and applied in the Sulige gas field, Ordos Basin. The following conclusions were drawn: First, The gas production contribution rates of pay zones based on the new model are fairly close to the measurements of the production profile logging, with errors less than 10%. Second, The overall drainage area of a gas well lies among those of each pay zone, and the total dynamic reserves of the well are close to the sum of the dynamic reserves of pay zones. Third, Higher permeability may lead to higher initial gas production of the pay zone, but the ultimate gas production contributions of pay zones are affected jointly by permeability and dynamic reserves. Finally, The new model has been successfully applied to the SZ block of the Sulige gas field, in which the fine evaluation of dynamic reserves, drainage areas, gas production, recovery factors, and remaining gas distributions of different layers was delivered, and the application results provide technical support for the future well placement and enhanced gas recovery of the block. [ABSTRACT FROM AUTHOR]

The application of the basin simulation method in reconstructing the pressure evolution process is frequently constrained by the limited availability of measured data. In order to establish a valid relation between logging data and paleo-pressure, this paper proposes a novel approach to constrain the pressure reconstructed by basin simulation method. The Eaton index N corresponding to the paleo-pressure of each period is calculated using inversion method, based on measured paleo-pressure by fluid inclusion PVTx method and logging data, in accordance with the Eaton formula. Subsequently, this value is utilized to calculate the paleo-pressure of other wells. The paleo-pressure results are compared with those reconstructed by basin simulation method to validate the reliability of the findings. The findings demonstrate a strong concurrence between the paleo-pressure calculated using the mean value of index N for each period and the reconstructed paleo-pressure obtained through basin simulation methodology, with an average error margin of less than ± 5%. Therefore, utilizing log data to constrain the paleo-pressure reconstructed by basin simulation method is a viable approach due to its ease of accessibility, strong continuity, and broad applicability and potential for application. This is particularly advantageous in regions where acquiring paleo-pressure data poses challenges. The paleo-dynamic conditions exert a significant influence on the distribution of gas and water in tight sandstone gas reservoirs, providing valuable insights for identifying favorable areas. [ABSTRACT FROM AUTHOR]

The juxtaposition of coal seams and tight gas reservoirs is a common geological structure in coal-bearing formations. Elucidating the production dynamics of coalbed methane (CBM) and tight gas from such overlaid formations holds significant importance for the synergistic development of coal-bearing resources. Initially, the study examines the gas and water production characteristics and reservoir average pressure evolution under separate development of CBM and tight gas. Subsequently, employing a wellbore node analysis method, it iteratively calculates pressure distribution characteristics under varying mass flow conditions, using wellbore pressure drop as a link to couple the mutual interference of pressure between coalseams and tight gas formations and their respective production characteristics. Finally, a dynamic gas production prediction model for co-production wells in the "coal seam above, tight below" juxtaposition relationship is established. The study analyzes the stable production capacity of co-production wells and the evolution of production contribution from each layer under different production systems, revealing that: (1) the stable production period of co-production wells (averaging 2 158 days) significantly exceeds that of CBM separate development. (2) The cumulative gas production of co-production wells sharing a single wellbore differs by only 2.56% compared to multiple drilling for separate development, demonstrating the strong economic benefits of CBM-tight gas combined production. (3) Due to the typical characteristics of early-stage single-phase drainage of CBM, its contribution to gas production in co-production wells exhibits an initial zero phase followed by a slow increase in the later period. [ABSTRACT FROM AUTHOR]

The SX area of the Ordos Basin in China is characterized by small thickness and considerable lateral variation of the reservoir, and high heterogeneity. It is difficult to identify gas and water by conventional P-wave seismic data without fully utilizing reservoir P-wave and S-wave information. Therefore, this study forms a series of seismic fluid detection technologies based on multi-wave seismic data, including the multi-wave “bright spot” feature analysis, multi-wave amplitude ratio technique, multi-wave amplitude versus offset analysis, multi-wave matched compression correlation analysis, and multi-wave pre-stack simultaneous inversion. The combined application of P- and S-waves facilitates visualized identification of fluids and improves the success rate of seismic prediction of underground gas-bearing features. The multi-wave interpretation technology series for low-permeability lithological gas reservoirs formed in this area has achieved a transformation from qualitative interpretation to quantitative prediction, and from lithological identification to fluid detection. These technologies have achieved significant geological results in the SX area.

In order to address the limitations of traditional methods for predicting gas production of tight gas wells in the Linxing area, such as a single data type, simplified mathematical models, and insufficient accuracy. A novel approach is proposed that relies on comprehensive geological and engineering data from gas wells in the field. Data from 48 gas wells in the field were collected and pre-processed to obtain 129 geological and engineering influencing factors, and the correlation coefficients of each factor were calculated, ranked and chipped, and finally 39 main controlling factors for gas well production were screened out. Three models of multiple regression, support vector machine and Bayesian ridge regression were developed and evaluated, and the highest R2 of the multiple regression model was 0.97. Relatively regression equations for daily gas and water production distribution were fitted and evaluated for their adequacy. The results demonstrated that the types of major control factors were consistent, and gas production was more sensitive than water production. Therefore, optimizing water control in gas wells with sufficient water production and adjusting the intensity of water control based on gas production adequacy is a feasible approach. [ABSTRACT FROM AUTHOR]

Effective production prediction is vital for optimizing energy resource management, designing efficient extraction strategies, minimizing operational risks, and informing strategic investment decisions within the energy sector. This paper introduces a Dual-Stage Attention Temporal Convolutional Network (DA-TCN) model to enhance the accuracy and efficiency of gas production forecasting, particularly for wells in tight sandstone reservoirs. The DA-TCN architecture integrates feature and temporal attention mechanisms within the Temporal Convolutional Network (TCN) framework, improving the model's ability to capture complex temporal dependencies and emphasize significant features, resulting in robust forecasting performance across multiple time horizons. Application of the DA-TCN model to gas production data from two wells in Block T of the Sulige gas field in China demonstrated a 19% improvement in RMSE and a 21% improvement in MAPE compared to traditional TCN methods for long-term forecasts. These findings confirm that dual-stage attention not only increases predictive accuracy but also enhances forecast stability over short-, medium-, and long-term horizons. By enabling more reliable production forecasting, the DA-TCN model reduces operational uncertainties, optimizes resource allocation, and supports cost-effective management of unconventional gas resources. Leveraging existing knowledge, this scalable and data-efficient approach represents a significant advancement in gas production forecasting, delivering tangible economic benefits for the energy industry. [ABSTRACT FROM AUTHOR]

Fracture geometries and drainage radius are essential parameters for developing a reasonable development plan for a single fractured well. However, owing to fracture hits, the complex fracture geometries bring challenges for parameter estimations. This paper establishes a well testing based model for a finite-conductivity fractured vertical well in radial composite reservoirs with dynamic supply and fracture networks. Based on the successive steady-state method, the point source function, pressure superposition principle, and boundary element method are used to solve the reservoir model, and the methods of discrete fracture and pressure superposition are used to solve the fracture model. By introducing the rate-normalized pseudopressure and material balance time, the variable fluid flux is equivalent to the constant fluid flux. The drainage radius value and fracture geometries are solved by fitting the log-log curves of pressure response, and case studies are performed. The results show that the drainage radius increases with the increase of production time and finally tends to a specific value, and it has an excellent exponential relationship with time. Also, the fracture geometries of the typical well are multiple-radial fracture networks. Through the study of dynamic drainage radius, the controlled reserves of single wells in unconventional gas reservoirs can be better determined, and it can also provide a theoretical basis for fracture evaluation, productivity prediction, and enhanced recovery study of the same type of tight gas reservoir. [ABSTRACT FROM AUTHOR]

Accurate production forecasting of tight gas reservoirs plays a critical role in effective gas field development and management. Recurrent-based deep learning models typically require extensive historical production data to achieve robust forecasting performance. This paper presents a novel approach that integrates transfer learning with the neural basis expansion analysis time series (N-BEATS) model to forecast gas well production, thereby addressing the limitations of traditional models and reducing the reliance on large historical datasets. The N-BEATS model was pre-trained on the M4 competition dataset, which consists of 100,000 time series spanning multiple domains. Subsequently, the pre-trained model was transferred to forecast the daily production rates of two gas wells over short-term, medium-term, and long-term horizons in the S block of the Sulige gas field, China's largest tight gas field. Comparative analysis demonstrates that the N-BEATS transfer model consistently outperforms the attention-based LSTM (A-LSTM) model, exhibiting greater accuracy across all forecast periods, with root mean square error improvements of 19.5%, 19.8%, and 26.8% of Well A1 for short-, medium-, and long-term horizons, respectively. The results indicate that the pre-trained N-BEATS model effectively mitigates the data scarcity challenges that hinder the predictive performance of LSTM-based models. This study highlights the potential of the N-BEATS transfer learning framework in the petroleum industry, particularly for production forecasting in tight gas reservoirs with limited historical data. [ABSTRACT FROM AUTHOR]

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Copyright of Petroleum Geology & Oilfield Development in Daqing is the property of Editorial Department of Petroleum Geology & Oilfield Development in Daqing and its content may not be copied or emailed to multiple sites or posted to a listserv without the copyright holder's express written permission. However, users may print, download, or email articles for individual use. This abstract may be abridged. No warranty is given about the accuracy of the copy. Users should refer to the original published version of the material for the full abstract. (Copyright applies to all Abstracts.)

The production performances of fractured tight gas wells are closely related to several complex and unknown factors, including the formation properties, fracture parameters, gas–water two-phase flow, and other nonlinear flow mechanisms. The rate transient analysis (RTA) results have significant uncertainties, which should be quantified to evaluate the formation and fracturing treatment better. This paper provides an efficient method for uncertainty quantification in the RTA of fractured tight gas wells with multiple unknown factors incorporated. The theoretical model for making forward predictions is based on a trilinear flow model, which incorporates the effects of two-phase flow and other nonlinear flow mechanisms. The normalized rates and material balance times of both water and gas phases are regarded as observations and matched with the theoretical model. The unknowns in the model are calibrated using the ensemble Kalman filter (EnKF), which applies an ensemble of multiple realizations to match the observations and updates the unknown parameters step by step. Finally, a comprehensive field case from Northwestern China is implemented to benchmark the proposed method. The results show that the parameters and rate transient responses have wide ranges and significant uncertainties before history matching, while all the realizations in the ensemble can have good matches to the field data after calibration. The posterior distribution of each unknown parameter in the model can be obtained after history matching, which can be used to quantify the uncertainties in the RTA of the fractured tight gas wells. The ranges and uncertainties of the parameters are significantly narrowed down, but the parameters are still with significant uncertainties. The main contribution of the paper is the provision of an efficient integrated workflow to quantify the uncertainties in RTA. It can be readily used in field applications of multi-fractured horizontal wells from tight gas reservoirs. [ABSTRACT FROM AUTHOR]

The Linxing gas field on the northeastern edge of Ordos Basin is mainly composed of multi-thin interbedded tight sandstone reservoirs. These reservoirs feature complex lithologies and low permeability, and are affected by multiple factors with unclear mechanisms, leading to difficulties in hydraulic fracturing operations and significant variability in operation outcomes. Therefore, this study designed and conducted a series of large-scale three-dimensional (3D) physical simulation experiments of hydraulic fracturing under different geological conditions, focusing on different rock components, clay contents, particle sizes, sedimentary cycles, and planar and longitudinal heterogeneities of the tight sandstone reservoirs in the Linxing gas field. According to the similarity criteria, the basic parameters of the experiments were determined by referencing the triaxial geostress, rock strength, wellbore structural parameters, and on-site fracturing operational parameters of the Permian Shihezi Formation. Based on the characteristics of the main reservoirs in typical wells of the Linxing gas field, 15 cubic rock cores were produced to account for different rock components, clay contents, particle sizes, sedimentary cycle combinations, and planar and longitudinal heterogeneity combinations. Fifteen sets of hydraulic fracturing simulation experiments were conducted, and the main controlling factors affecting the propagation of hydraulic fractures were summarized by analyzing the injection pressure curves and observing the fracture surfaces of rock samples. The results indicate that rock minerals, particle sizes, sedimentary cycles, and planar and longitudinal heterogeneities have a significant impact on fracture propagation patterns in tight reservoirs. The fracture surfaces are more prone to buckling with larger sandstone particle sizes, weaker cementation, higher clay content, and stronger planar heterogeneity, increasing the expansion pressure and difficulty in sand addition. Sedimentary cycles facilitate hydraulic fractures to propagate along the cycle planes, resulting in horizontal fractures. The difficulty of breaking through in retrograde cycle interfaces is greater than in prograde cycles. Interfaces between sand and mud layers, sand and coal layers, and natural weak sandstone surfaces are easily activated, leading to "工" or "T" shaped fractures. A combination of "工", "T", and "十" shaped fractures may occur in sand-mud multi-thin interlayers. This experimental study reveals the propagation patterns of hydraulic fractures under different geological conditions, providing insights for research in similar blocks.

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The exploration and development of tight sandstone gas reservoirs are controlled by high-quality river channel sand bodies on a large scale in Sichuan Basin. In order to improve the accuracy of sand body prediction and characterization, Multi-component exploration technology research has been carried out in Northwest Sichuan Basin. First, based on the array acoustic logging data, a forward modeling has been established to analyze the seismic response characteristics of the PS-wave data and P-wave data. The result shows that the response characteristics of the P-wave and PS-wave to the sand bodies with different impedance are different. And then through the analysis of logging data, the effectiveness of the forward modeling has been proved. When the sandstone velocity is close to the surrounding rocks, the P-wave performs as a weak reflection, which may lead to reduce the identification range of the sand bodies. However, the PS-wave exhibits strong reflection, which can identify this type of sand bodies. Finally, by comparing and explaining the PS-wave data and P-wave data, and integrating their attributes, the prediction accuracy of sand bodies is improved. Compared with the interpretation of a single P-wave, the results can significantly expand the distribution range of sand bodies, laying a foundation for improving the production capacity of single wells and reserve submission. [ABSTRACT FROM AUTHOR]

Tight gas is an extremely important unconventional oil and gas resource, and its efficient development can effectively alleviate the current tense energy situation. However, the geochemical characteristics and gas source analysis of fault adjusted tight gas reservoirs are currently insufficient. Therefore, based on experimental methods such as tight gas composition and hydrocarbon isotope determination, the geochemical characteristics of typical tight gas reservoirs were analyzed, and discussions were conducted on the genesis of tight gas and source rock properties in the study area. The research results found that the tight gas in the study area is mainly composed of light hydrocarbons, and the tight gas reservoir is an ideal geological body for carbon dioxide geological storage, with an estimated CO2 burial value of up to 3.43·109 tons. Meanwhile, high-temperature and high-pressure trapping environments can easily cause heavy hydrocarbons in the trap to break down into light hydrocarbons, resulting in a much higher δ13-C1 value in the carbon isotopes of tight gas compared to other carbon isotopes. The light hydrocarbon components of typical tight gas reservoirs are mainly oil associated gas types, while the heavy hydrocarbon components are mainly coal derived gas types. Moreover, the average organic carbon content in the tight gas in the study area is 6.67%, indicating that its source rocks are type I and II-1 kerogen, derived from underlying humic source rocks. Finally, the study found that the δ13-CO2 values of all dense gas samples ranged from 7.85% to 15.3%, and the carbon dioxide concentration was all below 6%, indicating that the source of carbon dioxide in dense gas is a mixed mode. [ABSTRACT FROM AUTHOR]

Blasingame production decline is an effective method to obtain permeability and single-well controlled reserves. The accurate Blasingame production decline curve needs an accurate wellbore pressure approximate solution of the real-time domain. Therefore, the aim of this study is to present a simple and accurate wellbore pressure approximate solution and Blasingame production decline curves calculation method of a multi-stage fractured horizontal well (MFHW) with complex fractures. A semi-analytical model of MFHWs in circle-closed reservoirs is presented. The wellbore pressure and dimensionless pseudo-steady productivity index JDpss (1/bDpss) are verified with a numerical solution. The comparison result reaches a good match. Wellbore pressure and Blasingame production decline curves are used to analyze parameter sensitivity. Results show that when the crossflow from matrix to natural fracture appears after the pseudo-state flow regime, the value of the inter-porosity coefficient has an obvious influence on the pressure approximate solution of the pseudo-steady flow regime in naturally fractured gas reservoirs. The effects of relevant parameters on wellbore pressure and the Blasingame decline curve are also analyzed. The method of pseudo-steady productivity index JDpss can applied to all well and reservoir models. [ABSTRACT FROM AUTHOR]

Making rate transient analysis (RTA) and formation evaluation for multi-fractured tight gas wells has always been a difficult problem. This is because the fluid flow in the formation has multiple nonlinear flow mechanisms, including gas-water two-phase flow, gas slippage, low-velocity non-Darcy flow, and stress-dependent permeability. In this paper, a novel RTA method is proposed for multi-fractured wells in tight gas reservoirs incorporating nonlinear flow mechanisms. The RTA method is based on an analytical model, which is modified from the classical trilinear flow model by considering all the nonlinear flow mechanisms. The concept of material balance time and normalized rate is used to process the production data for both water and gas phases. The techniques of approximate solutions in linear/bilinear flow regimes and type curve fitting are combined in the proposed RTA method. After that, the rate transient behaviors and influencing factors of multi-fractured tight gas wells are analyzed. A field case from Northwestern China is used to test the efficiency and practicability of the proposed RTA method. The results show that six flow regimes for both gas and water production performances are exhibited on the log-log plots of normalized production rate against material balance time. The rate transient responses are sensitive to the nonlinear flow mechanisms, and formation and fracture properties. The medium flow regimes are significantly affected by fracture number, fracture conductivity, fracture half-length, stress-dependent permeability, gas-water two-phase flow, and formation permeability, which should be considered in making RTA of fractured tight gas wells. The field case shows that both gas and water production performances can be well-fitted using the proposed RTA method. The major innovation of this paper is that a novel RTA method is proposed for fractured tight gas wells considering multiple nonlinear flow mechanisms, and it can be used to make reasonable formation and fracturing evaluations in the field. [ABSTRACT FROM AUTHOR]

Copyright of Petroleum Geology & Experiment is the property of Petroleum Geology & Experiment Editorial Office and its content may not be copied or emailed to multiple sites or posted to a listserv without the copyright holder's express written permission. However, users may print, download, or email articles for individual use. This abstract may be abridged. No warranty is given about the accuracy of the copy. Users should refer to the original published version of the material for the full abstract. (Copyright applies to all Abstracts.)

Due to the dissimilarity among different producing layers, the influences of inter-layer interference on the production performance of a multi-layer gas reservoir are possible. However, systematic studies of inter-layer interference for tight gas reservoirs are really limited, especially for those reservoirs in the presence of water. In this work, five types of possible inter-layer interferences, including both absence and presence of water, are identified for commingled production of tight gas reservoirs. Subsequently, a series of reservoir-scale and pore-scale numerical simulations are conducted to quantify the degree of influence of each type of interference. Consistent field evidence from the Yan'an tight gas reservoir (Ordos Basin, China) is found to support the simulation results. Additionally, suggestions are proposed to mitigate the potential inter-layer interferences. The results indicate that, in the absence of water, commingled production is favorable in two situations: when there is a difference in physical properties and when there is a difference in the pressure system of each layer. For reservoirs with a multi-pressure system, the backflow phenomenon, which significantly influences the production performance, only occurs under extreme conditions (such as very low production rates or well shut-in periods). When water is introduced into the multi-layer system, inter-layer interference becomes nearly inevitable. Perforating both the gas-rich layer and water-rich layer for commingled production is not desirable, as it can trigger water invasion from the water-rich layer into the gas-rich layer. The gas-rich layer might also be interfered with by water from the neighboring unperforated water-rich layer, where the water might break the barrier (eg weak joint surface, cement in fractures) between the two layers and migrate into the gas-rich layer. Additionally, the gas-rich layer could possibly be interfered with by water that accumulates at the bottom of the wellbore due to gravitational differentiation during shut-in operations. [ABSTRACT FROM AUTHOR]

Given the challenges of strong heterogeneity, poor reservoir properties, and low recovery rate in tight sandstone gas reservoirs, in-depth research was conducted on the factors affecting the recovery rate of tight sandstone gas reservoirs. Taking the Sulige gas field as the research object, starting from the research results of core experiments, the grey correlation analysis method is applied to calculate the correlation degree of geological and development factors affecting oil recovery, and the degree of influence of each parameter is determined through comparative analysis. The calculation results prove that the main influencing factor on the recovery rate of tight gas reservoirs is reservoir permeability, followed by the vertical to horizontal permeability ratio, porosity, reservoir thickness, and gas production rate. In the later development plan design of Sulige gas reservoir, parameters are adjusted based on the main factors that affect oil recovery of tight gas, providing support for the formulation of measures to improve oil recovery. [ABSTRACT FROM AUTHOR]

To address the significant challenges in determining the single-well production of tight gas and shale gas after hydraulic fracturing, artificial intelligence (AI) methods were implemented. Machine learning (ML) algorithms such as random forest (RF), extremely randomized trees (ET), lightweight gradient boosting machines (LightGBM), gradient boosting regression (GBR), and linear regression (LR) were utilized in conjunction with reservoir geology, engineering parameters, and production data to develop several foundational models for forecasting the production of unconventional gas wells. The accuracy of these models was evaluated. Based on this, improvements in the models' predictive accuracy and generalizability were achieved through the ensemble of machine learning models. Furthermore, this paper selected two representative tight and shale gas reservoirs to demonstrate the application of the ensemble model for well production forecasting, and a comparative analysis with actual production data was conducted. For tight gas reservoir A, the blending model achieved an MAE of 0.8419 and an MSE of 1.0930, with an R2 score of 0.8812. For shale gas reservoir B, the blending model achieved an MAE of 1.4841 and an MSE of 3.1629, with an R2 score of 0.9524. The results of the case studies indicate that the ensemble model approach employed in this study has a higher predictive accuracy and reliability than a single machine learning algorithm, and is capable of handling high-dimensional, large-scale, and imbalanced data, offering scientific validation and technical support for the assessment of the well productivity in tight and shale gas wells. [ABSTRACT FROM AUTHOR]

The exploitation of deep unconventional gas resources has gradually become more significant attributing to their huge reserves and the severe depletion of convention gas resources in the world. The proportion of deep unconventional gas reservoirs in the total gas resources cannot be underestimated, including shale gas, tight gas, and gas of coal seam. Due to the low permeability and porosity, hydraulic fracturing technology is still an important means to develop deep unconventional gas resources. However, the presence of fracturing fluids and water accumulation at the bottom of the wellbore significantly reduce gas production. The liquid loading model can be used to determine when the gas well begins to load the liquid. In this work, different types of liquid loading models are classified, and the applicability of different models is analyzed. At present, the existing critical liquid carrying models can be divided into mechanism models and semi-empirical models. The model established by Turner is a typical mechanism model. There are great differences in the application of a critical liquid loading model between vertical and horizontal wells. The field cases of a liquid loading model in different gas fields are provided and discussed. The mechanism of liquid loading models in recent years is introduced and analyzed. The physical simulations and experimental work therein are described and discussed to clarify the feasibility of the modeling mechanism. This article also presents the limitation and future work for improving the liquid loading models. [ABSTRACT FROM AUTHOR]

Copyright of Geology & Exploration is the property of Geology & Exploration Editorial Office and its content may not be copied or emailed to multiple sites or posted to a listserv without the copyright holder's express written permission. However, users may print, download, or email articles for individual use. This abstract may be abridged. No warranty is given about the accuracy of the copy. Users should refer to the original published version of the material for the full abstract. (Copyright applies to all Abstracts.)

In the mid-21st century, natural gas will enter its golden age, and the era of natural gas is arriving. This paper reviews the development stages of global natural gas industry and the enlightenment of American shale gas revolution, summarizes the development history and achievements of the natural gas industry in China, analyzes the status and challenges of natural gas in the green and low-carbon energy transition, and puts forward the natural gas industry development strategies under carbon neutral target in China. The natural gas industry in China has experienced three periods: start, growth, and leap forward. At present, China has become the fourth largest natural gas producer and third largest natural gas consumer in the world, and has made great achievements in natural gas exploration and development theory and technology, providing important support for the growth of production and reserves. China has set its goal of carbon neutrality to promote green and sustainable development, which brings opportunities and challenges for natural gas industry. Natural gas has significant low-carbon advantages, and gas-electric peak shaving boosts new energy development; the difficulty and cost of development are more prominent. For the national energy security and harmonious development between economy and ecology under the carbon neutral goal, based on the principle of "comprehensive planning, technological innovation, multi-energy complementarity, diversified integration, flexibility and efficiency, optimization and upgrading", the construction of the production-supplystorage-marketing system has to be improved so as to boost the development of the natural gas industry. First, it is necessary to strengthen efforts in the exploration and development of natural gas, making projects and arrangement in key exploration and development areas, meanwhile, it is urgent to make breakthroughs in key science theories and technologies, so as to increase reserve and production. Second, it should promote green and innovative development of the natural gas by developing new techniques, expanding new fields and integrating with new energy. Third, there is a demand to realize transformation and upgrading of the supply and demand structure of natural gas by strengthening the layout of pipeline gas, liquefied natural gas and the construction of underground gas storage, establishing reserve system for improving abilities of emergency response and adjustment, raising the proportion of natural gas in the primary energy consumption and contributing to the transformation of energy consumption structure, realizing low-carbon resources utilization and clean energy consumption. [ABSTRACT FROM AUTHOR]

The gas-water distribution and production heterogeneity of tight gas reservoirs have been summarized from experimental and geological observations, but the charging and accumulation mechanisms have not been examined quantitatively by mathematical model. The tight gas charging and accumulation mechanisms were revealed from a combination of physical simulation of nuclear magnetic resonance coupling displacement, numerical simulation considering material and mechanical equilibria, as well as actual geological observation. The results show that gas migrates into tight rocks to preferentially form a gas saturation stabilization zone near the source-reservoir interface. When the gas source is insufficient, gas saturation reduction zone and uncharged zone are formed in sequence from the source-reservoir interface. The better the source rock conditions with more gas expulsion volume and higher overpressure, the thicker the gas saturation stabilization and reduction zones, and the higher the overall gas saturation. When the source rock conditions are limited, the better the tight reservoir conditions with higher porosity and permeability as well as larger pore throat, the thinner the gas saturation stabilization and reduction zones, but the gas saturation is high. The sweet spot of tight gas is developed in the high-quality reservoir near the source rock, which often corresponds to the gas saturation stabilization zone. The numerical simulation results by mathematical model agree well with the physical simulation results by nuclear magnetic resonance coupling displacement, and reasonably explain the gas-water distribution and production pattern of deep reservoirs in the Xujiaweizi fault depression of the Songliao Basin and tight gas reservoirs in the Linxing–Huangfu area of the Ordos Basin.

The exploitation of deep unconventional gas resources has gradually become more significant attributing to their huge reserves and the severe depletion of convention gas resources in the world. The proportion of deep unconventional gas reservoirs in the total gas resources cannot be underestimated, including shale gas, tight gas, and gas of coal seam. Due to the low permeability and porosity, hydraulic fracturing technology is still an important means to develop deep unconventional gas resources. However, the presence of fracturing fluids and water accumulation at the bottom of the wellbore significantly reduce gas production. The liquid loading model can be used to determine when the gas well begins to load the liquid. In this work, different types of liquid loading models are classified, and the applicability of different models is analyzed. At present, the existing critical liquid carrying models can be divided into mechanism models and semi-empirical models. The model established by Turner is a typical mechanism model. There are great differences in the application of a critical liquid loading model between vertical and horizontal wells. The field cases of a liquid loading model in different gas fields are provided and discussed. The mechanism of liquid loading models in recent years is introduced and analyzed. The physical simulations and experimental work therein are described and discussed to clarify the feasibility of the modeling mechanism. This article also presents the limitation and future work for improving the liquid loading models.

Copyright of Corrosion & Protection in Petrochemical Industry is the property of Corrosion & Protection in Petrochemical Industry Editorial Office and its content may not be copied or emailed to multiple sites or posted to a listserv without the copyright holder's express written permission. However, users may print, download, or email articles for individual use. This abstract may be abridged. No warranty is given about the accuracy of the copy. Users should refer to the original published version of the material for the full abstract. (Copyright applies to all Abstracts.)

In current energy structure adjustments, the prominence of unconventional oil and gas resources continues to grow, with increasing attention being paid to tight gas, a major component of natural gas production. The Xujiahe Formation gas reservoir in the Western Sichuan Depression represents a typical tight gas reservoir and the study of its reservoir characteristics is a key focus for current and future exploration and development efforts. This review employs the PRISMA method to screen and integrate the primary findings of 26 documents spanning the period from 2008 to 2023, with the aim of providing a comprehensive overview of the progress and outcomes of research on the tight gas reservoir characteristics of the Xujiahe Formation in the Western Sichuan Depression. The selected research documents summarize the characteristics of the Xujiahe Formation tight gas reservoir in the Western Sichuan Depression from four perspectives: lithology, physical properties, reservoir space, and the main factors influencing reservoir quality. Through a review of these previous studies, it is evident that existing research has predominantly focused on the relationship between diagenesis and reservoir densification, indicating certain limitations. We also delve into the characteristics of tight gas sandstone reservoirs in the study area, considering their depositional systems, fracture development, cementation, and impact on the exploration and development of tight gas reservoirs. Additionally, we propose measures to stabilize and enhance tight gas production in the Xujiahe Formation in the Western Sichuan Depression. Moreover, we outline the next steps for further research and exploration. [ABSTRACT FROM AUTHOR]

The Jurassic strata constitute a focal area for recent exploration and development of tight gas reservoirs in the western Sichuan Basin. This study investigates the Jurassic Shaximiao Formation in the northern Longmenshan in the Western Sichuan basin, focusing on tight gas reservoirs. The research integrates core and outcrop observations, seismic interpretations, and burial history analyses to understand hydrocarbon source rocks, sedimentation, reservoir characteristics, and structural characteristics. The impact of Yanshan-Himalayan tectonic movements on tight gas reservoir accumulation in the Shaximiao Formation is dissected, primarily around the Qiulin structure. The Western Sichuan Depression basin's formation is influenced by gravitational gliding tectonics, which can be classified into the 'Three Zones and One Belt,' with Longmenshan in the frontal belt. Burial history analysis reveals distinct processes in the foreland belt and the depression basin. In the Qiulin area, gas reservoirs in the Shaximiao Formation are mainly charged by source rocks from the Xujiahe Formation. Tectonic movements play a significant role in creating favorable reservoirs and conditions for hydrocarbon migration and preservation. Natural gas accumulation is primarily controlled by fault connectivity to hydrocarbon sources and effective reservoir thickness. Gravitational sliding tectonics have shaped a fluvial-lacustrine environment for the Shaximiao Formation, with fluvial sand bodies acting as favorable reservoir zones. Small-scale normal faults formed by tectonic movements serve as conduits for natural gas migration. The research findings are of significant guidance for the exploration and development of tight oil and gas resources in western Sichuan basin. [ABSTRACT FROM AUTHOR]

Abstract The prediction of production capacity in tight gas wells is greatly influenced by the characteristics of gas–water two-phase flow and the fracture network permeability parameters. However, traditional analytical models simplify the nonlinear problems of two-phase flow equations to a large extent, resulting in significant errors in dynamic analysis results. To address this issue, this study considers the characteristics of gas–water two-phase flow in the reservoir and fracture network, utilizes a trilinear flow model to characterize the effects of hydraulic fracturing, and takes into account the stress sensitivity of the reservoir and fractures. A predictive model for gas–water two-phase production in tight fractured horizontal wells is established. By combining the mass balance equation with the Newton–Raphson iteration method, the nonlinear parameters of the flow model are updated step by step using the average reservoir pressure. The accuracy of the model is validated through comparisons with results from commercial numerical simulation software and field case applications. The research results demonstrate that the established semi-analytical solution method efficiently handles the nonlinear two-phase flow problems, allowing for the rapid and accurate prediction of production capacity in tight gas wells. Water production significantly affects gas well productivity, and appropriate fracture network parameters are crucial for improving gas well productivity. The findings of this work could provide more clear understanding of the gas production performance from the fractured tight-gas horizontal well.

In the process of tight gas development, ultra-long horizontal wells can increase the seepage area and provide guarantee for the effective development of tight gas reservoirs. In view of the technical problems such as long open hole section, poor wellbore stability, difficult trajectory control, difficult plugging in horizontal section and difficult running of completion casing in the drilling process of ultra long horizontal well, through tackling key problems of wellbore trajectory control and optimization technology, rotary steering tools were optimized, researching high-performance water-based drilling fluid, and floating casing running technology was matched to form the drilling and completion technology of ultra long horizontal well in tight gas. The drilling depth of well Jing 51-29H1 is 8 528 m and the horizontal section is 5 256 m long, seting a record for the longest horizontal section in the Asia-Pacific region, indicating that the ultra long horizontal section horizontal well drilling technology of tight gas reservoir can meet the development needs of tight gas field in Changqing Oilfield, and also provides a reference for the drilling of other ultra-long horizontal sections in China. [ABSTRACT FROM AUTHOR]

The gas-water distribution and production heterogeneity of tight gas reservoirs have been summarized from experimental and geological observations, but the charging and accumulation mechanisms have not been examined quantitatively by mathematical model. The tight gas charging and accumulation mechanisms were revealed from a combination of physical simulation of nuclear magnetic resonance coupling displacement, numerical simulation considering material and mechanical equilibria, as well as actual geological observation. The results show that gas migrates into tight rocks to preferentially form a gas saturation stabilization zone near the source-reservoir interface. When the gas source is insufficient, gas saturation reduction zone and uncharged zone are formed in sequence from the source-reservoir interface. The better the source rock conditions with more gas expulsion volume and higher overpressure, the thicker the gas saturation stabilization and reduction zones, and the higher the overall gas saturation. When the source rock conditions are limited, the better the tight reservoir conditions with higher porosity and permeability as well as larger pore throat, the thinner the gas saturation stabilization and reduction zones, but the gas saturation is high. The sweet spot of tight gas is developed in the high-quality reservoir near the source rock, which often corresponds to the gas saturation stabilization zone. The numerical simulation results by mathematical model agree well with the physical simulation results by nuclear magnetic resonance coupling displacement, and reasonably explain the gas-water distribution and production pattern of deep reservoirs in the Xujiaweizi fault depression of the Songliao Basin and tight gas reservoirs in the Linxing–Huangfu area of the Ordos Basin. [ABSTRACT FROM AUTHOR]

Faced with difficulties stemming from the complex interactions between tight gas sand bodies and fractures, when describing and identifying reservoirs, a composite reservoir model was established. By setting the supply boundary to characterize the superposition characteristics of sand bodies, a mathematical model of unstable seepage in fractured vertical wells in tight sandstone gas reservoirs was developed, considering factors such as stress sensitivity, fracture density and fracture symmetry. The seepage law and pressure response characteristics of gas wells in tight sandstone discontinuous reservoirs with stress sensitivity, semi-permeable supply boundary and complex fracture topology were determined, and the reliability of the model was verified. The research results more accurately display the pressure characteristic of a vertical well in the superimposed sand body with complex fractures and provide a more comprehensive model for tight gas production dynamic analysis and well test data analysis, which can more accurately guide the dynamic inversion of reservoir and fracture parameters. [ABSTRACT FROM AUTHOR]

There are abundant tight sandstone gas resources in the Sichuan Basin, which are the important objects of reserve and production increase and large-scale development. Due to their discontinuous sandbody distribution, narrow channels, and strong horizontal and vertical heterogeneity, however, conventional fracturing technologies cannot achieve the ideal stimulation effect here. In order to address this difficulty, this paper dissects the geology engineering characteristics of tight sandstone gas reservoirs in the western Sichuan Basin. Starting from the seepage mechanics theory, the concept of “multi-scale high-density” tight gas fracturing technology is put forward by fully referring to the experience of previous multi-round reservoir stimulation in the western Sichuan Basin and the idea of unconventional volume fracturing technology. In addition, its conceptual connotation, key technologies and implementation effects are illustrated. The following research results are obtained. First, the seepage characteristics make it necessary for the efficient production of tight gas reserves to increase fracture density and stimulated reservoir volume (SRV). Second, the “multi-scale high-density” fracturing technology emphasizes the rationality of high-density hydraulic fracture creation and the matching of multi-scale fracture flow capacity, and aims at establishing a multi-level fracture system with effective and steady gas flow in tight reservoirs through fracturing. Third, the “wide, dense, support, stable, and precise” fracturing technology is applied to improve single well production and estimated ultimate recovery (EUR). Fourth, the engineering practice of “multi-scale high-density” fracturing technology in the tight reservoirs of Jurassic Shaximiao Formation and Triassic Xujiahe Formation in the ZJ Gas Field realizes the average single well production rate of 15.6 × 104 m3/d, which is 1.96 times higher than that before the stimulation. Obviously, it provides powerful support for the operation of the ZJ Gas Field into a giant gas field with the reserves of 100 billion cubic meters. In conclusion, the formation of the concept and key technologies of “multi-scale high-density” fracturing technology effectively supports the efficient development of tight gas in the western Sichuan Basin and points out the following research direction of tight gas reservoir stimulation. The research results provide reference and guidance for the large-scale benefit development of tight gas in China.

Based on the analysis of Upper Paleozoic source rocks, source-reservoir-caprock assemblage, and gas accumulation characteristics in the Ordos Basin, the gas accumulation geological model of total petroleum system is determined. Then, taking the Carboniferous Benxi Formation and the Permian Taiyuan Formation and Shanxi Formation as examples, the main controlling factors of gas accumulation and enrichment are discussed, and the gas enrichment models of total petroleum system are established. The results show that the source rocks, faults and tight reservoirs and their mutual coupling relations control the distribution and enrichment of gas. Specifically, the distribution and hydrocarbon generation capacity of source rocks control the enrichment degree and distribution range of retained shale gas and tight gas in the source. The coupling between the hydrocarbon generation capacity of source rocks and the physical properties of tight reservoirs controls the distribution and sweet spot development of near-source tight gas in the basin center. The far-source tight gas in the basin margin is mainly controlled by the distribution of faults, and the distribution of inner-source, near-source and far-source gas is adjusted and reformed by faults. Generally, the Upper Paleozoic gas in the Ordos Basin is recognized in four enrichment models: inner-source coalbed gas and shale gas, inner-source tight sandstone gas, near-source tight gas, and far-source fault-transported gas. In the Ordos Basin, inner-source tight gas and near-source tight gas are the current focuses of exploration, and inner-source coalbed gas and shale gas and far-source gas will be important potential targets in the future.

Unconventional gas in the Sichuan Basin mainly includes shale gas and tight gas. The development of shale gas is mainly concentrated in the Ordovician Wufeng Formation–Silurian Longmaxi Formation, but has not made any significant breakthrough in the Cambrian Qiongzhusi Formation marine shale regardless of exploration efforts for years. The commercial development of tight sandstone gas is mainly concentrated in the Jurassic Shaximiao Formation, but has not been realized in the widespread and thick Triassic Xujiahe Formation. Depending on the geological characteristics of the Qiongzhusi Formation and Xujiahe Formation, the feedback of old wells was analyzed. Then, combining with the accumulation mechanisms of conventional gas and shale gas, as well as the oil/gas shows during drilling, changes in production and pressure during development, and other characteristics, it was proposed to change the exploration and development strategy from source and reservoir exploration to carrier beds exploration. With the combination of effective source rock, effective carrier beds and effective sandstone or shale as the exploration target, a model of unconventional gas accumulation and enrichment in carrier beds was built. Under the guidance of this study, two significant results have been achieved in practice. First, great breakthrough was made in exploration of the silty shale with low organic matter abundance in the Qiongzhusi Formation, which breaks the traditional approach to prospect shale gas only in organic-rich black shales and realizes a breakthrough in new areas, new layers and new types of shale gas and a transformation of exploration and development of shale gas from single-layer system, Longmaxi Formation, to multi-layer system in the Sichuan Basin. Second, exploration breakthrough and high-efficient development were realized for difficult-to-produce tight sandstone gas reserves in the Xujiahe Formation, which helps address the challenges of low production and unstable production of fracture zones in the Xujiahe Formation, promote the transformation of tight sandstone gas from reserves without production to effective production, and enhance the exploration and development potential of tight sandstone gas.

The Jurassic strata constitute a focal area for recent exploration and development of tight gas reservoirs in the western Sichuan Basin. This study investigates the Jurassic Shaximiao Formation in the northern Longmenshan in the Western Sichuan basin, focusing on tight gas reservoirs. The research integrates core and outcrop observations, seismic interpretations, and burial history analyses to understand hydrocarbon source rocks, sedimentation, reservoir characteristics, and structural characteristics. The impact of Yanshan-Himalayan tectonic movements on tight gas reservoir accumulation in the Shaximiao Formation is dissected, primarily around the Qiulin structure. The Western Sichuan Depression basin’s formation is influenced by gravitational gliding tectonics, which can be classified into the ‘Three Zones and One Belt,’ with Longmenshan in the frontal belt. Burial history analysis reveals distinct processes in the foreland belt and the depression basin. In the Qiulin area, gas reservoirs in the Shaximiao Formation are mainly charged by source rocks from the Xujiahe Formation. Tectonic movements play a significant role in creating favorable reservoirs and conditions for hydrocarbon migration and preservation. Natural gas accumulation is primarily controlled by fault connectivity to hydrocarbon sources and effective reservoir thickness. Gravitational sliding tectonics have shaped a fluvial-lacustrine environment for the Shaximiao Formation, with fluvial sand bodies acting as favorable reservoir zones. Small-scale normal faults formed by tectonic movements serve as conduits for natural gas migration. The research findings are of significant guidance for the exploration and development of tight oil and gas resources in western Sichuan basin.

Tight gas exhibits a large area of continuous accumulation distribution, strong reservoir heterogeneity, and significant differences in resource abundance. Traditional volumetric resource evaluation cannot characterize key parameters and resource heterogeneity, as well as differences in resource abundance plane distribution. Based on the basic exploration and development data of global unconventional oil and gas of PetroChina, the global commercial database of oil and gas basins, and the data management and spatial overlay analysis functions provided by ArcGIS software, ArcGIS spatial graph interpolation method(ArcGIS SGIM)and its seven-step technical process for evaluating tight gas resources were established. The process converts the key graphics and data parameters of the evaluation area into ArcGIS spatial vector data, delineate the evaluation area and evaluation units based on the similarity of geological attributes, and grid on the area. The common Kriging interpolation method is preferred to carry out spatial interpolation and assignment on each parameter using the grid as a unit, stack the key parameter grid map in space, calculate and integrate the grid resources. Finally, the geological resource amount, recoverable resource amount, abundance and map of the whole evaluation area are obtained. This method is applied to evaluate the tight gas resource of Timan-Pechora Basin in Russia. The results show that the total recoverable resource potential of Permian is 3 400×108 m³. The “sweet-spot areas” are mainly distributed in the uplift zone and piedmont depression zone in the north, south and east of the evaluation area. The northern and eastern piedmont depression zones have favorable reservoir formation combinations, shallow burial depth of Permian in the platform area, and the lowest exploration degree in some parts of Arctic sea. It is predicted to have the most potential and is an important stronghold for opening a strategic base for Arctic resources. [ABSTRACT FROM AUTHOR]