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Gas production and pressure from shale gas wells are highest early in the extraction process and decay rapidly over time. Skid-mounted compression equipment (SCE) in the shale gas gathering and transportation system (SGTS) can adapt to production changes in gas wells and can be deployed flexibly, improving equipment utilization. This paper examines the effects of node pressure and equipment type on the deployment scheme of SCE. Using a specific shale gas field production block as a case study, this paper proposes a method for multicycle operation and pressurizing deployment optimization in the SGTS, establishing a mixed-integer nonlinear programming (MINLP) model. Solving this optimization model yields the optimal deployment scheme of SCE at different times, the number of compression equipment, and the equipment utilization rate. The results show that in shale gas field production, SCE can be deployed flexibly, and most equipment utilization rates are above 0.8, with a maximum of 0.99. This not only achieves efficient use of equipment but also reduces the purchase cost, fully reflecting the importance of SCE in the SGTS. A sensitivity analysis was conducted to consider the impact of different costs and type combinations of SCE on the total production cost, and the results showed that the total cost of eight types was 6.28% lower than that of two types of booster equipment combinations. [ABSTRACT FROM AUTHOR]

Shale reservoirs are highly complex and are difficult to study using conventional reservoir simulation tools. This study introduces a novel methodology for estimating production from complex shale gas reservoirs by coupling decline curve analysis (DCA) with computational fluid dynamics (CFD) simulations. The proposed method uses exponential DCA to analyze production data from a dual porosity–permeability shale gas transport model. These complexities include fracture characteristics, geomechanical properties, nanopore confinement effects, and multiple flow mechanisms contributing to the total production performance. The shale gas transport model is validated through historical production data from Marcellus shale. The new methodology also tests fracture characteristics. It shows that increased porosity and permeability will increase the recoverable reserves but will have varying effects on the decline rate. The paper demonstrates the advantages of the proposed methodology over conventional reservoir simulation tools. It provides insights into the factors affecting shale gas production performance through the inclusion of the complexities of an unconventional shale gas reservoir. The paper provides a proof of concept on the particular reservoir of which the field data is provided—Barnett and Marcellus Shale. [ABSTRACT FROM AUTHOR]

The Upper Permian Wujiaping (WJP) Formation in the Yangtze Block (Southern China) has great potential for shale gas exploration. However, the sedimentary characteristics and environmental evolution of the WJP Formation are poorly understood. Based on 260 hand specimen samples obtained from 18 sections and 1 borehole in the eastern Yangtze Block, petrographic observations reveal that the WJP Formation is composed of 11 rock types. Combined with analyses of geochemical compositions, the sedimentary facies belts of the WJP Formation are divided into shoreland, shallow-water shelf, deep-water shelf shoal, restricted platform, and open platform. Bauxite was developed in the shoreland at the bottom of the WJP Formation, which is attributed to the Dongwu movement. The formation of paleo-uplift exerted a significant effect on paleogeomorphology and led to a major change in the sedimentary model from the underlying stratum to the WJP Formation. During the lower WJP Formation sedimentary period, gradual transgression occurred in the eastern Yangtze Block, and the lithology was mainly composed of clastic rocks. Shoreland, shallow-water shelf, and deep-water shelf were developed northeastward in turn. In the period of the upper WJP Formation, due to durative transgression, the area of the shoreland reduced southwestward. The lithology converted from clastic rocks into carbonates, and the restricted platform and open platform were developed northeastward. A few patched shoals formed in the restricted platform. [ABSTRACT FROM AUTHOR]

Wufeng–Longmaxi Formation and Qiongzhusi Formation are the significant shale gas exploration strata in China. The former has made a major breakthrough, and the exploration of the latter is restricted. At present, it shows good exploration potential in the Qiongzhusi Formation. Based on the field outcrop and core logging data, the production data from drilled shale gas wells and previous research results combined with the determination of organic matter content, laser Raman spectroscopy of organic matter, X‐ray diffraction experiments, and field emission scanning electron microscopy observations. This study compares the geological conditions and control factors of shale gas enrichment and high yield in the Wufeng–Longmaxi Formation and Qiongzhusi Formation and clarifies the enrichment mode of two sets of shale gas reservoirs. The results show that the organic geochemical conditions of two sets of shale reservoirs are similar, about 0.5%~4.5%. The quartz content of Wufeng–Longmaxi Formation shale (42.5%) is more than that of Qiongzhusi Formation (34.1%~40.2%), and the feldspar content (6.4%) is less than that of Qiongzhusi Formation (20.5~27.3%). The inorganic pores of the Qiongzhusi Formation are more developed than those of the Wufeng–Longmaxi Formation, and the pore size of inorganic pores can reach 100 nm~1 μm. Both of them have good preservation conditions. The enrichment of shale gas in the Wufeng–Longmaxi Formation is controlled by hydrocarbon generation reservoir‐preservation conditions, and the enrichment of shale gas in the Qiongzhusi Formation is mainly controlled by geological structure. It is of great significance to clarify the enrichment control factors of the Qiongzhusi Formation for effectively guiding the continuous exploration and development of the Qiongzhusi Formation. Shale gas exploration in the Qiongzhusi Formation has a very large prospect, which is expected to exceed the Longmaxi Formation. [ABSTRACT FROM AUTHOR]

Liquefied natural gas (LNG) exports from the United States have risen dramatically since the LNG‐export ban was lifted in 2016, and the United States is now the world's largest exporter. This LNG is produced largely from shale gas. Production of shale gas, as well as liquefaction to make LNG and LNG transport by tanker, is energy‐intensive, which contributes significantly to the LNG greenhouse gas footprint. The production and transport of shale gas emits a substantial amount of methane as well, and liquefaction and tanker transport of LNG can further increase methane emissions. Consequently, carbon dioxide (CO2) from end‐use combustion of LNG contributes only 34% of the total LNG greenhouse gas footprint, when CO2 and methane are compared over 20 years global warming potential (GWP20) following emission. Upstream and midstream methane emissions are the largest contributors to the LNG footprint (38% of total LNG emissions, based on GWP20). Adding CO2 emissions from the energy used to produce LNG, total upstream and midstream emissions make up on average 47% of the total greenhouse gas footprint of LNG. Other significant emissions are the liquefaction process (8.8% of the total, on average, using GWP20) and tanker transport (5.5% of the total, on average, using GWP20). Emissions from tankers vary from 3.9% to 8.1% depending upon the type of tanker. Surprisingly, the most modern tankers propelled by two‐ and four‐stroke engines have higher total greenhouse gas emissions than steam‐powered tankers, despite their greater fuel efficiency and lower CO2 emissions, due to methane slippage in their exhaust. Overall, the greenhouse gas footprint for LNG as a fuel source is 33% greater than that for coal when analyzed using GWP20 (160 g CO2‐equivalent/MJ vs. 120 g CO2‐equivalent/MJ). Even considered on the time frame of 100 years after emission (GWP100), which severely understates the climatic damage of methane, the LNG footprint equals or exceeds that of coal. [ABSTRACT FROM AUTHOR]

CO2 injection in shale reservoirs is more suitable than the conventional recovering methods due to its easier injectivity and higher sweep efficiency. In this work, Grand Canonical Monte Carlo (GCMC) simulation is employed to investigate the adsorption/desorption behavior of CH4-C4H10 and CH4-C4H10-CO2 mixtures in organic and inorganic nanopores during pressure drawdown and CO2 huff and puff processes. The huff and puff process involves injecting CO2 into the micro- and mesopores, where the system pressure is increased during the huffing process and decreased during the puffing process. The fundamental mechanism of shale gas recovery using the CO2 injection method is thereby revealed from the nanopore-scale perspective. During primary gas production, CH4 is more likely to be produced as the reservoir pressure drops. On the contrary, C4H10 tends to be trapped in these organic nanopores and is hard to extract, especially from micropores and inorganic pores. During the CO2 huffing period, the adsorbed CH4 and C4H10 are recovered efficiently from the inorganic mesopores. On the contrary, the adsorbed C4H10 is slightly extracted from the inorganic micropores during the CO2 puffing period. During the CO2 puff process, the adsorbed CH4 desorbs from the pore surface and is thus heavily recovered, while the adsorbed C4H10 cannot be readily produced. During CO2 huff and puff, the recovery efficiency of CH4 is higher in the organic pores than that in the inorganic pores. More importantly, the recovery efficiency of C4H10 reaches the highest levels in both the inorganic and organic pores during the CO2 huff and puff process, suggesting that the CO2 huff and puff method is more advanced for heavier hydrocarbon recovery compared to the pressure drawdown method. In addition to CO2 storage, CO2 sequestration in the adsorbed state is safer than that in the free state. In our work, it was found that the high content of organic matter, high pressure, and small pores are beneficial factors for CO2 sequestration transforming into adsorbed state storage. [ABSTRACT FROM AUTHOR]

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After 5 different plans of development, the Weiyuan block is struggling to maintain stable production and urgently needs a new method to improve the recovery rate. Practice at home and abroad shows that three-dimensional development can effectively improve the degree of vertical shale gas utilization. Therefore, this paper first analyzes the distribution of reservoirs in the Weiyuan block and calculates the distribution of remaining reserves through the methods of fine description of gas reservoirs and establishment of a three-dimensional geological model. The results show that the recovery degree of the platform in the main production area of Weiyuan is 35~60%, and the average remaining reserves of the wells are (1.2~3) × 108 m3, and there is three-dimensional development potential in the local area. Secondly, through the establishment of a fracture and rock mechanics model, the target layer system for three-dimensional development of the Weiyuan block is preliminary selected from five aspects, namely, remaining reserves, reservoir characteristics, fracture density, mechanical characteristics, and the comparison of the height of the fracture network. Finally, in order to check the correctness of the target layer for three-dimensional development and evaluate the effect of the three-dimensional development, four scenarios for the lower branch of the H8 platform are designed and numerically simulated using Petrel RE software. The results of the numerical simulation show that Option 2 is the most effective, which can increase the production of the platform by 1.76 × 108 m3, and the recovery rate grows from 16.4% to 31.0%, with an overall increase of 14.6%. The relevant understanding can provide a reference for the three-dimensional development strategy of the Weiyuan shale gas block. [ABSTRACT FROM AUTHOR]

Conventional logging interpretation methods qualitatively identify shale reservoirs using shale attribute parameters and interpretation templates. However, improving the identification accuracy of complex shale reservoirs is challenging due to the numerous evaluation parameters and the complexity of model calculations. To quantitatively characterize high-quality shale reservoirs effectively, this study utilizes two wells in the Fuling shale gas field as examples and establishes a comprehensive evaluation method for identifying high-quality shale gas reservoirs utilizing multi-fractal spectral analysis of well logs. First, the conventional well logs are qualitatively analyzed and evaluated via multiple fractals and R/S analysis. Subsequently, a gray relational analysis is employed to combine the production well logging, which reflects dimensionless productivity contributions, with the fractal characteristics of conventional well logs to obtain the corrected weight multifractal spectrum width ∆α' and fractal dimension D'. Comprehensive fractal evaluation indices λ and γ are introduced, forming three categories of productivity evaluation standards for shale gas reservoirs characterized by fractals. Finally, a validation well is employed to demonstrate the effectiveness of the evaluation method. The results indicate that the identification of high-quality shale gas reservoirs based on the above comprehensive fractal evaluation method can reflect the productivity classification level of fractured well sections, simplify the calculation of formation evaluation parameters, and avoid the problem of poor correlation between predicted sweet spot zones and gas production. This approach has wide applicability and value for identifying high-quality reservoir areas in shale gas reservoirs and provides technical support for the effective large-scale development of shale reservoirs. [ABSTRACT FROM AUTHOR]

Shale gas reservoirs with nanoporous media have become one of the primary resources for natural gas development. The nanopore diameters of shale reservoirs range from 5 to 200 nm, with permeability ranging from 1 × 10−9 to 1 × 10−6 μm2. The natural gas production from shale gas reservoirs is low, necessitating the use of multi-stage hydraulic fracturing in horizontal wells. Segmented multi-cluster perforation fracturing is an effective method for shale gas extraction in these wells. The number of clusters significantly impacts the productivity of horizontal wells. Therefore, it is essential to analyze the impact of cluster numbers on fracture productivity in shale gas reservoir development. In this study, the equivalent flow resistance method was applied to establish a productivity model for multi-stage hydraulic fracturing horizontal wells in shale gas reservoirs considering diffusion and slip. An approximate analytical solution was obtained, and the effects of cluster length, diffusion coefficient, and fracture network permeability on productivity were analyzed. The results show that gas production gradually increases with the increase in the number of clusters and cluster length. However, as the number of clusters increases, the interference between clusters leads to a decrease in the productivity of individual clusters. As the fracture permeability, fracture network permeability, and diffusion coefficient increase, shale gas production also gradually increases. The permeability of the fracture network has the greatest impact on productivity. These research results are beneficial for the design of clusters in horizontal well fracturing and are of great importance for the development and production of shale gas reservoirs. [ABSTRACT FROM AUTHOR]

The proficient application of multistage fracturing methods enhances the status of the Duvernay shale formation as a highly esteemed shale reservoir on a global scale. Nevertheless, the challenge is in accurately characterizing unconventional fracture behavior and predicting shale productivity due to the complex distributions of natural fractures, pre-existing faults, and reservoir heterogeneity. The present study puts forth a Geo-Engineering approach to comprehensively investigate the Duvernay shale reservoir in the vicinity of Crooked Lake. To begin with, on the basis of the experimental results and well-logging interpretations, a high-quality petrophysical and geomechanical model is constructed. Subsequently, the establishment of an unconventional fracture model (UFM) takes into account the heterogeneity of the reservoir and the interactions between hydraulic fractures and pre-existing natural fractures/faults and is further validated by 18,040 microseismic events. Finally, the analysis of well productivity is conducted by numerical simulations, revealing that the agreement between the simulated and observed production magnitudes exceeds 89%. This paper will guide the efficient development of increasingly important unconventional shale resources. [ABSTRACT FROM AUTHOR]

Organic-rich hot Qusaiba shale is the primary source rock of most of the Paleozoic hydrocarbon reservoirs of eastern and central Arabia. Representative near-surface Qusaiba shale samples were collected and characterized from one of its outcrop sections at the Tayma quadrangle in northwest Saudi Arabia. The petrophysical and geochemical characterization indicated porosity and permeability of 8.2% and 2.05 nD, respectively, with good total organic carbon (TOC) of 2.2 mg/g and mature kerogen of gas-prone type III. The tight characteristics of the formation can lead to high capillary pressure and extensive post-fracking water retention, leading to flow blockage and a reduction in gas productivity. Three different surfactants and one ionic liquid, namely, Triton X-100, Triton X-405 and Zonyle FSO surfactants and Ammoeng 102 ionic liquid, were tested as additives to fracking fluid to investigate their effectiveness in optimizing its performance. The chemical solutions exhibited no sign of instability when exposed to solution salinity and temperatures up to 70 °C. The investigated chemicals' performance was examined by measuring methane/chemical solutions' surface tension and their ability to alter shale's wettability. The results indicate that Zonyl FSO is the most effective chemical, as it is able to significantly reduce surface tension and, hence, capillary pressure by 66% when added at critical micelle concentration (CMC). Using Zonyl FSO surfactant at a maximum tested concentration of 0.2% induced a relatively smaller capillary pressure drop (54%) due to the drastic drop in the contact angle rendering shale very strongly water-wet. Such a drop in capillary pressure can lower the fracking fluid invasion depth and therefore ease the liquid blockage removal during the flowback stage, enhancing gas recovery during the extended production stage. Triton X-100 at CMC was the second most effective surfactant and was able to induce a quite significant 47% drop in capillary pressure when added at the maximum tested concentration of 0.05%. This was sufficient to remove any liquid blockage but was less likely to alter the wettability of the shale. Based on the findings obtained, it is suggested to reduce the blockage tendency during the fracking process and elevate any existing blockage during the flowback stage by using Zonyl FSO at CMC where IFT is at its minimum with a higher contact angle. [ABSTRACT FROM AUTHOR]

Featured Application: The findings of this study can be utilized to enhance the operational parameters of the clean drilling process in shale gas horizontal wells. Additionally, the research offers technical solutions to prevent the accumulation of cuttings beds and mitigate drilling obstructions, while also providing theoretical backing for the development of specialized borehole purification tools for shale gas. The extraction of shale gas via horizontal drilling presents considerable challenges, primarily due to the accumulation of cuttings within the annular space, resulting in increased friction, torque, and potential drilling complications. To address this issue, the study proposes an experimental setup aimed at simulating cuttings transport under various operational conditions, with a particular emphasis on gas wells. The methodology encompasses the modulation of the drilling fluid flow rate and the drill's rotational speed to examine the transport velocity of cuttings. Furthermore, the study analyzes the impact of annular eccentricity on return volume, transport time, and cuttings bed height. Critical initiation velocities for cuttings across different motion modes were also determined, and theoretical calculations were compared with empirical data. The findings indicate that an increased flow rate of drilling fluid and higher rotation speed substantially improve the transport of cuttings, thereby minimizing bed formation, whereas increased eccentricity hinders this process. The results revealed that the theoretical model showed a greater overestimation of the start-up velocity for spherical particles, with average errors ranging from 15.50% to 17.56%. In contrast, the model exhibited better accuracy for non-spherical (flaky) particles, with errors between 8.63% and 9.61%. Under non-rotating conditions, the average error of the model was approximately 8.32%, while the introduction of drill tool rotation increased the average error to 11.94%. These results have the potential to optimize operational parameters in shale gas well drilling and may contribute to the development of specialized borehole purification tools. [ABSTRACT FROM AUTHOR]

Shale gas, as an environmentally friendly fossil energy resource, has gained significant commercial development and shows immense potential. However, accurately predicting shale gas production faces substantial challenges due to the complex law of decline, nonlinear and non-stationary features in production data, which greatly repair the robustness of current models in predicting shale gas production time series. To address these challenges and improve accuracy in production forecasting, this paper introduces a novel and innovative approach: a hybrid proxy model that combines the bidirectional long short-term memory (BiLSTM) neural network and random forest (RF) through deep learning. The BiLSTM neural network is adept at capturing long-term dependencies, making it suitable for understanding the intricate relationships between input and output variables in shale gas production. On the other hand, RF serves a dual purpose: reducing model variance and addressing the concept drift problem that arises in non-stationary time series predictions made by BiLSTM. By integrating these two models, the hybrid approach effectively captures the inherent dependencies present in long and nonstationary production time series, thereby reducing model uncertainty. Furthermore, the combination of BiLSTM and RF is optimized using the recently-proposed marine predators algorithm (MPA) to fine-tune hyperparameters and enhance the overall performance of the proxy model. The results demonstrate that the proposed BiLSTM-RF-MPA model achieves higher prediction accuracy and demonstrates stronger generalization capabilities by effectively handling the complex nonlinear and nonstationary characteristics of shale gas production time series. Compared to other models such as LSTM, BiLSTM, and RF, the proposed model exhibits superior fitting and prediction performance, with an average improvement in performance indicators exceeding 20%. This innovative framework provides valuable insights for forecasting the complex production performance of unconventional oil and gas reservoirs, which sheds light on the development of data-driven proxy models in the field of subsurface energy utilization. [ABSTRACT FROM AUTHOR]

Currently, horizontal well fracturing is indispensable for shale gas development. Due to the variable reservoir formation morphology, the drilling trajectory often deviates from the high-quality reservoir, which increases the risk of fracturing. Accurately recognizing low-amplitude structures plays a crucial role in guiding horizontal wells. However, existing methods have low recognition accuracy, and are difficult to meet actual production demand. In order to improve the drilling encounter rate of highquality reservoirs, we propose a method for fine recognition of low-amplitude structures based on the non-subsampled contourlet transform (NSCT). Firstly, the seismic structural data are analyzed at multiple scales and directions using the NSCT and decomposed into low-frequency and high-frequency structural components. Then, the signal of each component is reconstructed to eliminate the low-frequency background of the structure, highlight the structure and texture information, and recognize the lowamplitude structure from it. Finally, we combined the drilled horizontal wells to verify the lowamplitude structural recognition results. Taking a study area in the west Sichuan Basin block as an example, we demonstrate the fine identification of low-amplitude structures based on NSCT. By combining the variation characteristics of logging curves, such as organic carbon content (TOC), natural gamma value (GR), etc., the real structure type is verified and determined, and the false structures in the recognition results are checked. The proposed method can provide reliable information on lowamplitude structures for optimizing the trajectory of horizontal wells. Compared with identification methods based on traditional wavelet transform and curvelet transform, NSCT enhances the local features of low-amplitude structures and achieves finer mapping of low-amplitude structures, showing promise for application. [ABSTRACT FROM AUTHOR]

Shale gas is a prospective cleaner energy resource and the exploration and development of shale gas has made breakthroughs in many countries. Structure deformation is one of the main controlling factors of shale gas accumulation and enrichment in complex tectonic areas in southern China. In order to estimate the shale gas capacity of structurally deformed shale reservoirs, it is necessary to understand the systematic evolution of organic pores in the process of structural deformation. In particular, as the main storage space of high-over-mature marine shale reservoirs, the organic matter pore system directly affects the occurrence and migration of shale gas; however, there is a lack of systematic research on the fractal characteristics and deformation mechanism of organic pores under the background of different tectonic stresses. Therefore, to clarify the above issues, modular automated processing system (MAPS) scanning, low-pressure gas adsorption, quantitative evaluation of minerals by scanning (QEMSCAN), and focused ion beam scanning electron microscopy (FIB-SEM) were performed and interpreted with fractal and morphology analyses to investigate the deformation mechanisms and structure of organic pores from different tectonic units in Silurian Longmaxi shale. Results showed that in stress concentration areas such as around veins or high-angle fractures, the organic pore length-width ratio and the fractal dimension are higher, indicating that the pore is more obviously modified by stress. Under different tectonic backgrounds, the shale reservoir in Weiyuan suffered severe denudation and stronger tectonic compression during burial, which means that the organic pores are dominated by long strip pores and slit-shaped pores with high fractal dimension, while the pressure coefficient in Luzhou is high and the structural compression is weak, resulting in suborbicular pores and ink bottle pores with low fractal dimension. The porosity and permeability of different forms of organic pores are also obviously different; the connectivity of honeycomb pores with the smallest fractal dimension is the worst, that of suborbicular organic pores is medium, and that of long strip organic pores with the highest fractal dimension is the best. This study provides more mechanism discussion and case analysis for the microscopic heterogeneity of organic pores in shale reservoirs and also provides a new analysis perspective for the mechanism of shale gas productivity differences in different stress–strain environments. [ABSTRACT FROM AUTHOR]

The Carboniferous strata in the northeastern Junggar Basin are an important exploration field for natural gas in the basin. However, volcanic rocks have long been the primary exploration target. In contrast, the exploration and research of clastic rocks associated with source formations have been largely overlooked, resulting in an insufficient understanding of the reservoir forming conditions and exploration potential of Carboniferous clastic rocks. Through the evaluation of Carboniferous source rocks, effective source stove characterization, clastic reservoir evaluation, oil and gas source correlation, and reservoir formation model construction in this region, three key findings have been made. First, the Carboniferous in the northeastern Junggar Basin has developed three sets of high-quality gas source rocks: the Dishuiquan Formation, the Songkalsu B Member, and the Shiqiantan Formation. These formations correspond to three hydrocarbon source centers: the Sannan--Dishuiquan Sag, the Wucaiwan Sag--Dajing area, and the Dongdao Haizi Sag--Baijiahai High. Second, the Carboniferous system in the northeast has developed multiple types of large-scale reservoirs, including sand conglomerates, sandstones, turbidites, dolomitic rocks, and shale. These reservoirs are generally characterized by low porosity to ultra-low porosity and low permeability to ultra-low permeability reservoirs. There is a dissolution pore development zone at depths of 2900-4500 m. Third, a comparison of oil and gas sources reveals that all three sets of gas source rocks contribute to the natural gas found in the northeast, with obvious characteristics of near-source reservoir formation. The Carboniferous clastic rocks host two types of natural gas reservoirs: unconventional and conventional near-source reservoirs. It is predicted that there is an orderly accumulation pattern of shale gas, tight sandstone gas, and conventional natural gas reservoirs. This study reveals that the Carboniferous clastic rock source and reservoir configuration in the northeastern Junggar Basin is highly favorable, and the natural gas reservoirs in source and near-source clastic rocks represent important exploration directions. [ABSTRACT FROM AUTHOR]

Through the analysis of natural gas composition, carbon and hydrogen isotopes of alkane gases, reservoir bitumen, source rock conditions, and source--reservoir combinations, this study clarifies the differences in gas sources and the origins of natural gas in the Permian Changxing Formation--Triassic Feixianguan Formation on both sides of the Kaijiang--Liangping Trough. Additionally, it identifies favorable exploration directions for coal-formed gas generated by the Longtan Formation in the Sichuan Basin. The following understanding was obtained: (1) The natural gas in the Changxing--Feixianguan formations mainly composed of alkane gas, typical of dry gas. (2) The carbon isotope values of methane and ethane in the Changxing--Feixianguan formations on the east side of the trough are lower than those on the west side. Specifically, the ethane carbon isotope value in the Longgang Gas Field on the west side is higher than that in the Yuanba Gas Field, while the methane hydrogen isotope value is lower in the Longgang Gas Field compared to the Yuanba Gas Field. (3) The natural gas in the Dongyuezhai, Puguang, and Yuanba gas fields predominantly originates from sapropelic organic matter of the Wujiaping Formation, with kerogen types II1--I; in contrast, the Longgang Gas Field contains a mixture of coal-formed gas and oil-type gas, with a slightly higher content of coal-formed gas, originating from mixed organic matter of the Wujiaping Formation, with kerogen type II1--II2. (4) Multiple types of gas, such as coal rock gas, tight sandstone gas, and shale gas, can be formed within the Longtan Formation. The Suining--Luzhou and Langzhong--Guang'an--Fuling areas are identified as favorable zones for the exploration of coal rock gas and marine--continental transitional shale gas, respectively. Additionally, the reef and shoal development areas of the Changxing Formation in the Suining--Hechuan and Guang'an--Nanchong regions are also favorable exploration areas for coal-formed gas. [ABSTRACT FROM AUTHOR]

This study aims to explore the reservoir characteristics and formation mechanisms of ultra-deep shale gas in the Ordovician–Silurian Wufeng–Longmaxi Formation in the Sichuan Basin in order to provide theoretical support and practical guidance for the exploration and development of ultra-deep shale gas. With recent breakthroughs in ultra-deep shale gas exploration, understanding its organic matter development, mineral composition, and reservoir space characteristics has become particularly important. The background of this research lies in the significant potential of ultra-deep shale gas, which remains inadequately understood, necessitating an in-depth analysis of its pore structure and reservoir quality. Through a systematic study of the ultra-deep shale in well FS1 of Sichuan Basin, that the following was found: (i) The ultra-deep shale in the Wufeng–Longmaxi Formation is mainly composed of quartz and clay minerals, exhibiting high total organic carbon (TOC) and high porosity characteristics, indicating it is in an overmature thermal evolution stage. (ii) Organic pores and microcracks in the ultra-deep shale are more developed compared to middle-shallow and deep shale, forming a complex pore structure that is conducive to gas storage. (iii) In the diagenesis process, the dissolution and recrystallization of the biogenic skeleton promote the cementation between autogenetic quartz particles, forming a rigid skeleton that effectively inhibits the impact of mechanical compaction. (iv) The overpressure environment created by the hydrocarbon generation process, along with gas production from hydrocarbon cracking, can effectively offset the mechanical compaction of overburden pressure on micropores, and this overpressure environment also promotes the further development of microfractures, which is beneficial for the development and preservation of ultra-deep shale pores. In summary, this study not only reveals the reservoir characteristics and formation mechanisms of ultra-deep shale but also provides essential references for the exploration and development of ultra-deep shale gas in the Sichuan Basin and similar regions, emphasizing the ongoing significance of research in this field. [ABSTRACT FROM AUTHOR]

Shale gas, mainly consisting of adsorbed gas and free gas, has served a critical role of supplying the growing global natural gas demand in the past decades. Considering that the adsorbed methane has contributed up to 80% of the total gas in place (GIP), understanding the methane adsorption behaviors is imperative to an accurate estimation of total GIP. Historically, the single-site Langmuir model, with the assumption of a homogeneous surface, is commonly applied to estimate the adsorbed gas amount. However, this assumption cannot depict the methane adsorption characteristics due to various compositions and pore sizes of shales. In this work, a multi-site model integrating the energetic heterogeneity in adsorption is derived to predict methane adsorption on shale. Our results show that the multi-site model is capable of addressing the heterogeneity of shales by a wide range of adsorption energy distributions (owing to the complex compositions and different pore sizes), which is different from the single-site model only characterized by single adsorption energy. Consequently, the multi-site model results have better accuracy against the experimental data. Therefore, applying the multi-site Langmuir model for estimating GIP in shales can achieve more accurate results compared with using the traditionally single-site model. [ABSTRACT FROM AUTHOR]

Great progress has been made in marine shale gas of Wufeng–Longmaxi formations in the Sichuan Basin. However, shale gas exploration in the complex structural belt around the Sichuan Basin still faces great challenges. In this study, shales of Wufeng–Longmaxi formations collected from the northern Guizhou were taken as the studied target, organic matter (OM) characteristics, mineral composition, pore structure, methane adsorption capacity and in situ desorption gas content were measured, and the controlling factors of shale gas content were further discussed. The results indicated that the sedimentary facies of Wufeng–Longmaxi formations in north Guizhou varies from shallow‐water shelf facies to deep‐water shelf facies from south to north, and organic‐rich shales are primarily distributed in Daozhen‐Xishui areas, with a maximum thickness of about 80–100 m. Organic‐rich shales are characterized by high total organic carbon (TOC) content, high thermal maturation and type I–II1 kerogens, which can be comparable with those in commercially produced shale gas field in Sichuan Basin. High‐quality shale gas reservoirs generally have a high content of brittle minerals, making them easier to be fractured. OM pores are the dominanted pore type in the studied shales, followed by intergranular pores associated with brittle minerals, dissolution pores within carbonate grains and microcracks, while clay mineral‐related pores are poorly developed. The Wufeng–Longmaxi Formation shales generally have strong methane adsorption capacities, but these vary greatly across different areas. Shale gas adsorption capacity is primarily controlled by TOC content and thermal maturation level. Similarly, total gas content, including desorption gas and lost gas, varies greatly in different areas, and it is obviously lower than that in Fuling and Luzhou shale gas field, due to the loss of shale gas and low‐pressure coefficient in the complex structural zone. It is worth explaining that shale gas is not always low in northern Guizhou, which is determined by burial depth and the distance of great fractures. Shale gas content is relatively high in LY1 well and DY1 well in Xishui‐Daozhen area, and it is extremely low in TY1 well and AY1 well in Tongzi‐Zheng'an area. Shale gas content in the same structural unit is primarily influenced by TOC content, OM pore development degree and water saturation. However, different structural units have different shale gas contents, due to the differences in preservation conditions. Shale reservoirs with good preservation conditions, that is, wide and gentle structure, far from a large fault and great burial depth, generally have high shale gas contents. [ABSTRACT FROM AUTHOR]

In response to the unclear understanding of fracture propagation and intersection interference in zipper fracturing under the factory development model of deep shale gas wells, a coupled hydro-mechanical model for zipper fracturing considering the influence of natural fracture zones was established based on the finite element - discrete element method. The reliability of the model was verified using experimental data and field monitoring pressure increase data. Taking the deep shale gas reservoir in southern Sichuan as an example, the propagation and interference laws of fracturing fractures under the influence of natural fracture zones with different characteristics were studied. The results show that the large approaching angle fracture zone has a blocking effect on the forward propagation of fracturing fractures and the intersection of inter well fractures. During pump shutdown, hydraulic fractures exhibit continued expansion behavior under net pressure driving. Under high stress difference, as the approaching angle of the fracture zone increases, the response well pressure increase and the total length of the fractured fracture show a trend of first decreasing and then increasing, and first increasing and then decreasing, respectively. Compared to small approach angle fracture zones, natural fracture zones with large approach angles require longer time and have greater difficulty to intersect. The width of fractures and the length of natural fractures are negatively and positively correlated with the response well pressure increase, respectively, and positively and negatively correlated with the time required for intersection, the total length of hydraulic fractures, and fracturing efficiency, respectively. As the displacement distance of the well increases, the probability of fracture intersection decreases, but the regularity between displacement distance and the response well pressure increase and the total length of fractures is not obvious. [ABSTRACT FROM AUTHOR]

Based on sedimentary characteristics of the fine-grained rocks of the lower submember of second member of the Lower Cretaceous Shahezi Formation (K1sh2L) in the Lishu rift depression, combined with methods of organic petrology, analysis of major and trace elements as well as biological marker compound, the enrichment conditions and enrichment model of organic matter in the fine-grained sedimentary rocks in volcanic rift lacustrine basin are investigated. The change of sedimentary paleoenvironment controls the vertical distribution of different lithofacies types in the K1sh2L and divides it into the upper and lower parts. The lower part contains massive siliceous mudstone with bioclast-bearing siliceous mudstone, whereas the upper part is mostly composed of laminated siliceous shale and laminated fine-grained mixed shale. The kerogen types of organic matter in the lower and upper parts are types II2-III and types I-II1, respectively. The organic carbon content in the upper part is higher than that in the lower part generally. The enrichment of organic matter in volcanic rift lacustrine basin is subjected to three favorable conditions. First, continuous enhancement of rifting is the direct factor increasing the paleo-water depth, and the rise of base level leads to the expansion of deep-water mudstone/shale deposition range. Second, relatively strong underwater volcanic eruption and rifting are simultaneous, and such event can provide a lot of nutrients for the lake basin, which is conducive to the bloom of algae, resulting in higher productivity of types I-II1 kerogen. Third, the relatively dry paleoclimate leads to a decrease in input of fresh water and terrestrial materials, including Type III kerogen from terrestrial higher plants, resulting in a water body with higher salinity and anoxic stratification, which is more favorable for preservation of organic matter. The organic matter enrichment model of fine-grained sedimentary rocks of volcanic rift lacustrine basin is established, which is of reference significance to the understanding of the organic matter enrichment mechanism of fine-grained sedimentary rocks of Shahezi Formation in Songliao Basin and even in the northeast China. [ABSTRACT FROM AUTHOR]

Based on the oil and gas exploration in the Sichuan Basin, combined with data such as seismic, logging and geochemistry, the basic geological conditions, hydrocarbon types, hydrocarbon distribution characteristics, source-reservoir relationship and accumulation model of the Upper Triassic-Jurassic continental whole petroleum system in the basin are systematically analyzed. The continental whole petroleum system in the Sichuan Basin develops multiple sets of gas-bearing strata, forming a whole petroleum system centered on the Triassic Xujiahe Formation source rocks. The thick and high-quality source rocks in the Upper Triassic Xujiahe Formation provide sufficient gas source basis for the continental whole petroleum system in the basin. The development of conventional-unconventional reservoirs provides favorable space for hydrocarbon accumulation. The coupling of faults and sandbodies provides a high-quality transport system for gas migration. Source rocks and reservoirs are overlapped vertically, and there are obvious differences in sedimentary environment, reservoir lithology and physical properties, which lead to the orderly development of inner-source shale gas, near-source tight gas, and far-source tight-conventional gas in the Upper Triassic-Jurassic, from bottom to top. The orderly change of geological conditions such as burial depth, reservoir physical properties, formation pressure and hydrocarbon generation intensity in zones controlled the formation of the whole petroleum system consisting of structural gas reservoir in thrust zone, shale gas-tight gas reservoir in depression zone, tight gas reservoir in slope zone, and tight gas-conventional gas reservoir in uplift zone on the plane. Based on the theory and concept of the whole petroleum system, the continental shale gas and tight gas resources in the Sichuan Basin have great potential, especially in the central and western parts with abundant unconventional resources. [ABSTRACT FROM AUTHOR]

The geochemical properties of fracturing flowback fluids indirectly indicate the fracturing efficiency of the reservoir, the interaction between the reservoir and injected water, and the preservation of oil and gas, thereby offering robust data support for identifying fracturing flowback fluid sources, assessing fracturing effects, and proposing stimulation strategies. In this study, the ion characteristics, total salinity, and stable isotope ratio of fracturing flowback fluids of the Z202H1 and Z203 wells in Western Chongqing were measured. The findings suggest that with the extension of flowback time, the geochemical properties of fracturing flowback fluids evolve toward higher salinity and heavier stable isotope ratios, ultimately stabilizing. Upon comparing the water–rock reaction intensity and the rate of total salinity increase in the fracturing flowback fluids, it is concluded that fracturing flowback fluids contain a mixture of formation water. Because water–rock reactions elevate the total salinity of fracturing flowback fluids, we introduce the Water–Rock Reaction Intensity Coefficient (IR) to denote the intensity of these reactions. Based on the IR value, the binary mixture model for fracturing fluids in fracturing flowback fluids was adjusted. With the increase in flowback time, the content of fracturing fluids in fracturing flowback fluids of Z202H1 and Z203 stabilized at about 55% and 40% respectively. During the same flowback period, the fracturing flowback fluids of the Z203 well exhibit a higher total salinity, a heavier stable isotope ratio, a greater IR, and a lower fracturing fluid content in fracturing flowback fluids. This suggests that the fracturing effect of the Z203 well is superior to that of the Z202H1 well, leading to a higher production capacity of the Z203 well. [ABSTRACT FROM AUTHOR]

Evaluating shale gas reservoir economic viability remains challenging due to different factors such as long transient flow period and liquid loading resulting in successful shut-ins. Such factors cause fluctuations in production data, with inherent noise impacting analysis methods like decline curve analysis (DCA). In this research, we investigated data smoothing techniques as an alternative to noise removal methods. By applying these techniques, the essential characteristics of the periodic events and signals are retained while reducing the influence of noise making identifying and analyzing patterns easier. Applying seven smoothing techniques to three shale gas datasets with different noise levels to investigate their performance, then, utilizing the cluster-based local outlier factor (CBLOF) algorithm to remove noise from the production data, then, applying seven different DCA models to the original, smoothed, and processed data with CBLOF, the study found that smoothing the data facilitated the extraction of the well's signals. Different smoothing techniques exhibited varying spike levels. The goodness of fit was superior using LOWESS and Fast Fourier Transform (FFT) methods compared to Binomial Smoothing. Moreover, each smoothing technique yielded variations in prediction using the same DCA model. Applying the DCA models that commonly underestimate the reserve to the smoothed data led to further underestimations; however, the DCA models that commonly reserve overestimating reserves also leaned towards underestimations. The Duong's DCA model achieved the highest correlation coefficient (R2), whereas the Wang's DCA model recorded the lowest. In conclusion, this research highlights the benefits of smoothing shale gas production data for better analysis.

Abstract Conventional logging interpretation methods qualitatively identify shale reservoirs using shale attribute parameters and interpretation templates. However, improving the identification accuracy of complex shale reservoirs is challenging due to the numerous evaluation parameters and the complexity of model calculations. To quantitatively characterize high-quality shale reservoirs effectively, this study utilizes two wells in the Fuling shale gas field as examples and establishes a comprehensive evaluation method for identifying high-quality shale gas reservoirs utilizing multi-fractal spectral analysis of well logs. First, the conventional well logs are qualitatively analyzed and evaluated via multiple fractals and R/S analysis. Subsequently, a gray relational analysis is employed to combine the production well logging, which reflects dimensionless productivity contributions, with the fractal characteristics of conventional well logs to obtain the corrected weight multifractal spectrum width ∆α' and fractal dimension D’. Comprehensive fractal evaluation indices λ and γ are introduced, forming three categories of productivity evaluation standards for shale gas reservoirs characterized by fractals. Finally, a validation well is employed to demonstrate the effectiveness of the evaluation method. The results indicate that the identification of high-quality shale gas reservoirs based on the above comprehensive fractal evaluation method can reflect the productivity classification level of fractured well sections, simplify the calculation of formation evaluation parameters, and avoid the problem of poor correlation between predicted sweet spot zones and gas production. This approach has wide applicability and value for identifying high-quality reservoir areas in shale gas reservoirs and provides technical support for the effective large-scale development of shale reservoirs.

The lithofacies and thermal maturity of the over-mature Lower Cambrian marine shale in the Northern Guizhou Region, and their impacts on reservoir properties in this shale were analyzed by combining geochemistry, mineralogy, and gas adsorption methods. Ten lithofacies were identified, and the dominant lithofacies in the studied shale are lean-total organic carbon (TOC) argillaceous-rich siliceous shale (LTAS), medium-TOC siliceous shale (MTSS), and rich-TOC siliceous shale (RTSS). Since the gas generation potential of organic matter was weak, meso- and macro-pores were compressed or filled during the thermal evolution stage with a vitrinite reflectance (RO) range of 3.0%–4.0%. The controlling factors for methane adsorption capacity in the shale samples are significantly influenced by TOC content rather than thermal maturity. Among the RTSS, MTSS, and LTAS samples, RTSS exhibits the highest favorability for preserving hydrocarbon gas, followed by MTSS. The shale types in this study play a significant role in determining the properties of shale reservoirs, serving as an effective parameter for evaluating shale gas development potential. The RTSS and MTSS with a RO range of 2.0%–3.0% stand out as the most favorable target shale types for shale gas exploration and development.

Accurately predicting the estimated ultimate recovery (EUR) of shale gas wells is key to formulating a shale gas reservoir development plan. However, in practice, determining the EUR remains challenging due to the complex dynamic characteristics of shale gas production, which first decreases rapidly and then slowly. In this study, based on material balance theory and equivalent seepage resistance theory and considering crucial factors including primary water, adsorption, and pore effects, a new production model for fractured horizontal shale gas wells is developed. The calculation process is designed by using Newton's iterative method. The shale gas well EUR prediction method is verified, and the factors influencing the EUR are analyzed. The results show that adsorption has a significant effect on production, especially on the Langmuir volume. Moreover, ignoring the influence of primary water, which exists in shale gas reservoirs in the form of bound water, results in an overestimation of the EUR. Furthermore, production positively correlates with the fracture half-length and the number of fractures, but the action mechanisms of these two factors differ. Unlike the number of fractures, which predominantly affects the initial stage of production, the fracture half-length has a more nuanced role. It is capable of altering the stimulated reservoir volume zone, thereby exerting influence over the entire production life cycle.

The Lower Silurian Longmaxi Formation is a major horizon for shale gas development in the Changning block in Sichuan Basin. In this study, the fracture features in the Longmaxi Formation in the Changning block were investigated through outcrop observation, core description, inclusion testing, and Fullbore Formation MicroImage logging. The results showed that tectogenetic shear fractures dominated the Longmaxi Formation, with maximum principal stress in the SSW, NW, and NE directions. According to fracture features and stress analysis, three phases of faults were generated by tectonic movements after the buried depth reached a maximum in the study area: phase 1 nearly EW-trending faults formed in the middle-late Yanshanian, phase 2 NE-trending faults formed from the end of the Yanshanian to the early Himalayan, and phase 3 NW-trending faults formed from the middle Himalayan to the present. According to the regression analysis of the tested shale gas production and faults, the faults with a throw of > 200 m could have a great effect on gas production, and high-yield wells were generally located over 1 km away from faults. Based on the dissection of tectonic styles and typical wells drilled in the Changning block, three shale gas accumulation models were established: wide gentle syncline + internal smalxl fault, subdued anticline + large fault, and slope + internal fault. The study reveals the mechanism of fault influence on shale gas accumulation in the Longmaxi Formation in the Changning block and provides a reference for efficient shale gas production in the Sichuan Basin.

Preservation conditions are key to enriching shallow shale gas. Therefore, the veins of two typical wells in the Shixi syncline in northern Guizhou as research objects. Based on core observation, vein thin-section observation, cathodoluminescence, calcite in situ U-Pb dating, fluid inclusion microthermometry, Raman spectrum shift, single well basin simulation, and C-O isotope geochemical analysis, the researchers clarified the characteristics of the veins and the differences in paleofluid activity, as well as their significance for shale gas preservation. The results showed that: 1) a small number of high-angle fractures had developed mainly in the Shixi syncline in northern Guizhou. The width of viens is small and filled primarily with early calcite-quartz and late calcite. The inclusions were mainly methane and brine. The proportion of brine inclusions in the SD1 well was greater than that in the SX1 well. The SD1 well has experienced more intense second-stage uplift and denudation, and the consequent gas loss is serious. 2) The results of the C-O isotope analysis showed that most of the vein-forming fluids were derived from marine carbonate rocks. The O3b had obvious negative deviations of δ13C and δ18O, which were modified by exogenous or deep hydrothermal fluid. The C-O isotope difference between the vein bodies and the surrounding rock of the SX1 well was small, and the preservation conditions were better. 3) The difference in gas content in the Shixi syncline depends on the degree of damage to gas reservoir preservation conditions caused by burial depth and other factors. Shixi syncline is a wide and gentle syncline with central retention enrichment mode. Therefore, clarifying the development of shale veins, the characteristics of paleofluid activity, and their significance for shale gas preservation can lay a foundation for studying the enrichment mechanism of shallow shale gas and thus guide further exploration and development.

Abstract The Youjiang Basin is the main area of the Middle Devonian shale gas resources in southern China, with complex geological conditions, diverse stratigraphic structures, low level of exploration and limited hydrocarbon geological data. In this study, a method is proposed for evaluating the regional shale gas preservation conditions, by which it is easy to obtain information (using available data from regional geological maps) and to process data (processed by computer software). This method was applied to the evaluation of the preservation conditions of the Middle Devonian shale gas in the Youjiang Basin. Information extracted from geologic maps includes exposed stratum, magmatic rock distribution, stratigraphic occurrence and surface fracture distribution. Evaluation criteria for three indexes (stratigraphy index, dip angle index and fracture index) were established to classify the preservation conditions into five types from good to bad. Based on the calculated values of comprehensive index (CI), the comprehensive evaluation each area: 11621.23 km2 for CI of 0.7–1.0, 37162.67 km2 for CI of 0.5–0.7, 57784.43 km2 for CI of 0.3–0.5, 69303.77 km2 for CI of 0.1–0.3, and 69303.77 km2 for CI of 0.0–0.1, accounting for 3.19%, 10.19%, 15.84%, 18.99% and 51.80% of the whole area, respectively. These results are highly consistent with the actual exploration discoveries, showing that in the northern and central parts of the Guizhong Basin, the southern part of the Xidamingshan Uplift, and the northern part of the Qiannan Basin, there are large areas with good shale gas preservation conditions.

Objective For the early selection and evaluation of unconventional gas resources such as shale gas and dissolved gas, it is often difficult to obtain formation burial depth by seismic structural interpretation due to the lack of seismic data. Therefore, it is necessary to effectively predict the burial depth of the target layer using other non-seismic data. Methods Both regional geological maps and digital elevation model (DEM) are widely covered and easily accessible basic data. In this study, a new method for predicting structural height and buried depth of target layer is established by superposing regional DEM information with geological map which contains the attitude of stratum, trend of underground structures, as well as the relation between buried depth of underground layer and age of surface layer. Results This method is effective for predicting the burial depth of Marine strata with relatively stable sedimentary thickness. The buried depth of the Lower Silurian Longmaxi Formation in Sichuan Basin and its periphery is predicted based on 36 geological maps with scale of 1∶200 000 and DEM data, and then the contour map of the buried depth of Longmaxi Formation provides important parameters for the evaluation of shale gas preservation conditions in this area. Conclusion The method of predicting the burial depth of Marine strata by using non-seismic data such as regional geological map and DEM can not only provide effective support for the early selection evaluation of shale gas, but also can be applied to the resource evaluation of water-soluble gas in deep high-pressure aquifers and the structural optimization of CO2 geological storage in deep saline aquifers.

The article analyzes resilience factors of tight oil and gas production in the USA. The US is the only country in the world that currently produces shale hydrocarbons on a commercial scale, though other petroleum states try to emulate their success in this sphere. The American shale revolution became possible due to a massive application of hydrofracking in combination with horizontal drilling to produce tight oil and gas. Therefore, the mighty technological potential of the American petroleum sector became the key success factor of the US shale revolution. However, technological breakthroughs are necessary, but not sufficient for ensuring a stable development of the shale industry. Of particular importance is the institutional framework of the US shale sector that is characterized by an efficient system of subsurface use, a powerful financial and industrial base, a long-term strategy of the state support for R&D, a reasonable fiscal policy, a transparent regulation, as well as a competitive and diversified structure of the shale sector. This unique combination of factors will be extremely difficult to replicate in other countries. When constructing long-term scenarios of oil and gas production, the US Energy Information Administration proceeds from the key assumptions of resource availability and rates of improving production technologies. The analysis of the shale phenomenon permits to conclude that these two factors are interconnected – the continuous technological progress of the sector ensures the enhanced oil and gas recovery ratio. As a result, the production growth is accompanied by the growth of resource availability. The limits to this trend are not visible yet, and, therefore, it means that the upside potential of shale production is not exhausted.

Over the last 10 years, the China Geological Survey has deployed 137 slim-hole shale gas geological exploration wells for coring entire wellbores. These wells are primarily located in new blocks and geological formations where neighboring well data are insufficient, beyond the scope of developed oil fields in China, or outside of oil and gas company mining-right areas. The drilling rig equipment, coring tools, and core drill bits of slim-hole shale gas drilling technology are different from those associated with traditional petroleum drilling. Many studies have been conducted on non-coring slim-hole drilling technology. This paper focuses on coring technology and drilling safety, summarizing a set of high-efficiency shale gas drilling equipment and technology systems based on geological drilling equipment and techniques (that can be used for solid mineral exploration). We report on: 1) an improved vertical shaft drilling rig adapted to shale gas well control safety; 2) high-efficiency core drilling techniques, focusing on coring tools, and techniques incorporating an inverted tower drilling tool combination, air circulation follow-through technology, and expanded casing technology; 3) research progress on high-efficiency core drill bits, including non-planar tooth polycrystalline diamond compact bits and impregnated diamond core bits, along with their application effects. This research provides substantial advances in drill-core technology and improvements in exploration efficiency. Moreover, it provides a reference frame for well structural design and selection of construction technology for shale gas exploration drilling projects.

Abstract Field observations frequently demonstrate stress fluctuations resulting from the reservoir depletion. The development of reservoirs, particularly the completion of infill wells and refracturing, can be significantly impacted by stress changes in and around drainage areas. Previous studies mainly focus on plane fractures and few studies consider the influence of complex transport and storage mechanism and irregular fracture geometry on stress evolution in shale gas reservoirs. Based on the embedded discrete fracture model (EDFM) and finite-volume method (FVM), a coupled geomechanics/fluid model has been successfully developed considering the adsorption, desorption, diffusion and slippage of shale gas. This model achieves coupling simulation of natural fractures, hydraulic fractures with complex geometry, storage and transport mechanism, reservoir stress, and pore-elastic effect. The open-source software OpenFOAM is used as the main solver for this model. The stress calculation and productivity simulation of the model are verified by the classical poroelasticity problem and the simulation results of published research and commercial simulator with EDFM respectively. The simulation results indicate that σxx, σyy, σxy and Δσ changes with time and space due to the time effect and anisotropy of formation pressure depletion; Due to the influence of different mechanisms on shale gas storage and transport, the reservoir pressure and stress distribution under different mechanisms are different; Among them, the stress with full mechanisms differs the most compared to the stress without any mechanism. The reservoir with stronger stress sensitivity (smaller Biot coefficient) is less sensitive to formation pressure depletion, and the stress variation range is smaller. For reservoirs with weak stress sensitivity, formation pressure depletion is more likely to lead to stress reversal. Under the influence of fracture geometry, the pressure depletion regions caused by the three types of fracture geometry are approximately rectangular, parallelogram and square, respectively. The corresponding σxx, σyy and Δσ also have great differences in spatial distribution and values. Therefore, the time effect, shale gas storage and transport mechanism and the influence of complex fracture geometry should be considered when predicting pressure depletion induced stress under the condition of simultaneous production. This study is of great significance for understanding the evolution law of stress induced by pressure consumption, as well as the design of infill wells and repeated fracturing.

Based on an elaboration of the resource potential and annual production of tight sandstone gas and shale gas in the United States and China, this paper reviews the researches on the distribution of tight sandstone gas and shale gas reservoirs, and analyzes the distribution characteristics and genetic types of tight sandstone gas reservoirs. In the United States, the proportion of tight sandstone gas in the total gas production declined from 20%–35% in 2008 to about 8% in 2023, and the shale gas production was 8 310×108 m3 in 2023, about 80% of the total gas production, in contrast to the range of 5%–17% during 2000–2008. In China, the proportion of tight sandstone gas in the total gas production increased from 16% in 2010 to 28% or higher in 2023. China began to produce shale gas in 2012, with the production reaching 250×108 m3 in 2023, about 11% of the total gas production of the country. The distribution of shale gas reservoirs is continuous. According to the fault presence, fault displacement and gas layer thickness, the continuous shale gas reservoirs can be divided into two types: continuity and intermittency. Most previous studies believed that both tight sandstone gas reservoirs and shale gas reservoirs are continuous, but this paper holds that the distribution of tight sandstone gas reservoirs is not continuous. According to the trap types, tight sandstone gas reservoirs can be divided into lithologic, anticlinal, and synclinal reservoirs. The tight sandstone gas is coal-derived in typical basins in China and Egypt, but oil-type gas in typical basins in the United States and Oman.

We present a systematic summary of the geological characteristics, exploration and development history and current state of shale oil and gas in the United States. The hydrocarbon-rich shales in the major shale basins of the United States are mainly developed in six geological periods: Middle Ordovician, Middle–Late Devonian, Early Carboniferous (Middle–Late Mississippi), Early Permian, Late Jurassic, and Late Cretaceous (Cenomanian–Turonian). Depositional environments for these shales include intra-cratonic basins, foreland basins, and passive continental margins. Paleozoic hydrocarbon-rich shales are mainly developed in six basins, including the Appalachian Basin (Utica and Marcellus shales), Anadarko Basin (Woodford Shale), Williston Basin (Bakken Shale), Arkoma Basin (Fayetteville Shale), Fort Worth Basin (Barnett Shale), and the Wolfcamp and Leonardian Spraberry/Bone Springs shale plays of the Permian Basin. The Mesozoic hydrocarbon-rich shales are mainly developed on the margins of the Gulf of Mexico Basin (Haynesville and Eagle Ford) or in various Rocky Mountain basins (Niobrara Formation, mainly in the Denver and Powder River basins). The detailed analysis of shale plays reveals that the shales are different in facies and mineral components, and “shale reservoirs” are often not shale at all. The United States is abundant in shale oil and gas, with the in-place resources exceeding 0.246×1012 t and 290×1012 m3, respectively. Before the emergence of horizontal well hydraulic fracturing technology to kick off the “shale revolution”, the United States had experienced two decades of exploration and production practices, as well as theory and technology development. In 2007–2023, shale oil and gas production in the United States increased from approximately 11.2×104 tons of oil equivalent per day (toe/d) to over 300.0×104 toe/d. In 2017, the shale oil and gas production exceeded the conventional oil and gas production in the country. In 2023, the contribution from shale plays to the total U.S. oil and gas production remained above 60%. The development of shale oil and gas has largely been driven by improvements in drilling and completion technologies, with much of the recent effort focused on “cube development” or “co-development”. Other efforts to improve productivity and efficiency include refracturing, enhanced oil recovery, and drilling of “U-shaped” wells. Given the significant resources base and continued technological improvements, shale oil and gas production will continue to contribute significant volumes to total U.S. hydrocarbon production.

Abstract The key scientific problem to be solved in this paper is the optimal development and utilization model and the economic evaluation model of China's land-phase shale oil and gas resources, and the purpose of the research is to promote the large-scale commercial development and utilization of China's shale oil and gas resources, and to safeguard China's oil and gas energy security and the sustainable development of the economy. The article proposes to adopt the small surface element volume method (oil content rate method) to evaluate the pure shale oil resources, adopt the Cobb–Douglas production function model as the optimization model to measure the boundary production capacity of shale oil and gas, construct the optimal development and utilization model for shale oil and gas resources considering the five first-level safeguard indexes, namely, science and technology (A), capital (K), talents (L), reserves (S) and ecological environment (E), and establish the basic constraint model for the optimal development and utilization of shale oil and gas resources. The basic constraint model, as well as the evaluation model of economic coefficients for the development and utilization of shale oil and gas resources were established. The pure shale oil resources are mainly calculated based on the movable oil content of shale. In the paper, the S 1 of normal pyrolysis (300 °C) is regarded as movable oil, and the sum of S 1 and evaporated hydrocarbon (light hydrocarbon) loss is the movable oil content of shale. The integrated geological-physical exploration-engineering comprehensive evaluation of China’s land-phase shale oil-rich and high-yielding “sweet spot” is an important prerequisite for the realization of shale oil and gas resources to build production scale and effective development, and the least-squares method is used to estimate the average production function, the distance to the maximum value of the residuals, and the boundary capacity production function. The average production function and residual maximum distance are estimated by the least squares method, and the production function of the boundary capacity is derived, and the quotient of the boundary capacity and the actual capacity is calculated to get the capacity utilization rate, which can be used to analyze the potential of future shale oil and gas growth. The development of shale oil and gas resources in a target block requires comprehensive consideration of the first-level guarantee indicators such as science and technology (A), capital (K), talents (L), reserves (S) and ecological environment (E), as well as more than 10 s-level indicators and a number of third-level indicators, in order to ensure that the oil companies maximize their profits by organizing the development and production. The economic coefficient can be expressed as the ratio of economically recoverable resources to geological reserves. The larger the economic coefficient for the development and utilization of shale oil and gas resources is, the better the economy of the area is, and the larger the proportion of shale oil and gas resources that can be exploited. There is little special literature on the optimal development and utilization model of shale oil and gas resources and energy security among many research results at home and abroad. The evaluation of pure shale oil using the small surface element volume method (oil content rate method) and the construction of the boundary capacity calculation model, the optimal development of the basic constraints model and the economic evaluation model that we have determined, although they can not yet fully cover all the links and factors related to the development and utilization of shale oil and gas resources, are not yet fully covered by our research work. However, our research work has given the model more geological and economic theoretical connotations, and provided an economic basis and technical reference for the large-scale and commercial development and utilization of shale oil and gas resources as an effective alternative to oil imports.

Objective The prediction of abnormal formation pressure is a challenging issue in oil and gas development. With the continuous development of unconventional reservoirs such as shale gas and tight sandstone gas, the complexity of geopressure systems has increased. The coexistence of overpressure and underpressure in the same area often occurs, making it important to accurately characterize complex pressure systems. Methods In this work, two sets of overpressure systems and one set of underpressure systems formed in the Jurassic shale gas reservoir and tight sandstone reservoir in the Fuxing area were analysed. The geophysical responses and sensitive elastic parameters of overpressure and underpressure were analysed. The bulk modulus of the mudstone formation was strongly correlated with the formation pressure over the underpressure-overpressure interval. Based on this, an integrated prediction method for overpressure and underpressure based on the bulk modulus of mudstone was proposed and applied in this area by using well log and seismic data. The key of this method is to use the mudstone of overpressure and underpressure formations for integrated pressure prediction, reducing the influence of lithological changes. Second, the bulk modulus, which is directly related to the physical mechanism of abnormal pressure, was selected as the input parameter to improve the accuracy. Results According to the results of pressure prediction in the study area, the preservation conditions of the strong overpressure system in the Dongyuemiao Member are good, the pressure structure is stable, and the maximum pressure coefficient is approximately 2.0. The preservation conditions of the overpressure system in the Lianggaoshan Formation are relatively poor, with large lateral differences in pressure structure characteristics, and the maximum pressure coefficient is approximately 1.65; the pressure coefficient of the underpressure system in the Lianggaoshan Formation is approximately 0.5 to 1.0, and it has a certain coupling effect with the underlying overpressure system. Conclusion The predictions of overpressure and underpressure using well logs and seismic data in the study area both achieved high agreement with the measured data.

Objective The Fuling Gas Field as the first commercial shale gas field in China has stably achieved an annual gas production of over 7 billion cubic meters in recent years, which is a good development result. With the increasing demand for development, the development targets have gradually shifted from the high-pressured shale gas reservoirs, e.g., the Jiaoshiba region, to the normal-pressured shale gas reservoirs of the Baima region. In 2021, the Baima area submitted a proven reserve of 104.883 billion cubic meters, consolidating its geological resource foundation. Development geology evaluation and target optimization are the first steps to efficiently achieve the utilization of reserves. Methods Based on core testing, well logging interpretation, seismic prediction, and gas testing data, the favourable intervals and targets for the development of normal-pressured shale gas in the Baima area were evaluated in this study. Results The research results indicate that the organic-rich shale of the Ordovician Wufeng Formation and Silurian Longmaxi Formation in the Baima area was deposited on the deep-water shelf. Thereinto, the deep-water shelf siliceous shale is the most favourable layer for development. The key parameters for the development geology evaluation of normal-pressured shale gas include the formation pressure coefficient, porosity, natural fractures, and stress properties. Conclusion A geological parameter system has been established for the development of target areas, which suggests that the southern part of the Baima Syncline can be selected as the first target for development and production. The Baima Region has achieved large-scale economic production and can be an important reference for the development of normal-pressured shale gas.

Abstract Deep shale has the characteristics of large burial depth, rapid changes in reservoir properties, complex pore types and structures, and unstable production. The whole-rock X-ray diffraction (XRD) analysis, reservoir physical property parameter testing, scanning electron microscopy (SEM) analysis, high-pressure mercury intrusion testing, CO2 adsorption experimentation, and low-temperature nitrogen adsorption–desorption testing were performed to study the pore structure characteristics of marine shale reservoirs in the southern Sichuan Basin. The results show that the deep shale of the Wufeng Formation Longyi1 sub-member in the Luzhou area is superior to that of the Weiyuan area in terms of factors controlling shale gas enrichment, such as organic matter abundance, physical properties, gas-bearing properties, and shale reservoir thickness. SEM is utilized to identify six types of pores (mainly organic matter pores). The porosities of the pyrobitumen pores reach 21.04–31.65%, while the porosities of the solid kerogen pores, siliceous mineral dissolution pores, and carbonate dissolution pores are low at 0.48–1.80%. The pores of shale reservoirs are mainly micropores and mesopores, with a small amount of macropores. The total pore volume ranges from 22.0 to 36.40 μL/g, with an average of 27.46 μL/g, the total pore specific surface area ranges from 34.27 to 50.39 m2/g, with an average of 41.12 m2/g. The pore volume and specific surface area of deep shale gas are positively correlated with TOC content, siliceous minerals, and clay minerals. The key period for shale gas enrichment, which matches the evolution process of shale hydrocarbon generation, reservoir capacity, and direct and indirect cap rocks, is from the Middle to Late Triassic to the present. Areas with late structural uplift, small uplift amplitude, and high formation pressure coefficient characteristics favor preserving shale gas with high gas content and production levels.

Abstract This work introduces and discusses the impacts of the water bridge on gas adsorption and diffusion behaviors in a shale gas-bearing formation. The density distribution of the water bridge has been analyzed in micropores and meso-slit by molecular dynamics. Na+ and Cl− have been introduced into the system to mimic a practical encroachment environment and compared with pure water to probe the deviation in water bridge distribution. Additionally, practical subsurface scenarios, including pressure and temperature, are examined to reveal the effects on gas adsorption and diffusion properties, determining the shale gas transportation in realistic shale formation. The outcomes suggest carbon dioxide (CO2) usually has higher adsorption than methane (CH4) with a water bridge. Increasing temperature hinders gas adsorption, density distribution decreases in all directions. Increasing pressure facilitates gas adsorption, particularly as a bulk phase in the meso-slit, whereas it restricts gas diffusion by enhancing the interaction strength between gas and shale. Furthermore, ions make the water bridge distributes more unity and shifts to the slit center, impeding gas adsorption onto shale while encouraging gas diffusion. This study provides updated guidelines for gas adsorption and transportation characteristics and supports the fundamental understanding of industrial shale gas exploration and transportation.

Well logging interpretation and evaluation of reservoirs in horizontal wells plays an important role in shale gas exploration and development. The accuracy of the interpreted petrophysical parameters is directly affected by well logging curves. This study focuses on a horizontal well targeting deep shale gas layers in the Luzhou block, Southern Sichuan Basin. It employs an interactive forward and inversion scheme to precisely reconstruct the borehole trajectory using a comprehensive dataset encompassing well logs, mud logs, and seismic data. The research introduces a method for anisotropic correction of sonic log, crucial for calculating reservoir parameters, and assess payzone targeting in the horizontal well. The research results show that the interactive forward and inverse simulation method can achieve the recovery of horizontal well borehole trajectory and finely delineate the sublayers, improving the evaluation accuracy of platinum target drilling encounter ratio by over 6%. Numerically simulated acoustic wave can be used to carry out the anisotropy correction of acoustic wave in horizontal wells and calculate reservoir parameters, reducing the relative error in computed porosity to 1.72%. The comprehensive logging evaluation results from both geological and engineering aspects provide the data basis for planning the fracturing program of the shale gas horizontal well. This research has established a new method and idea for well logging evaluation in shale gas horizontal wells, marking a significant step toward integrating geological and engineering aspects in shale gas exploration. [ABSTRACT FROM AUTHOR]

Recent exploration efforts have revealed significant industrial gas flow from the Wujiaping Formation marine shale in the Longmen-Wushankan area of the eastern Sichuan Basin, underscoring its considerable exploration potential. In this study, the reservoir characteristics and exploration potential of the Wujiaping Formation shale gas in this area are further evaluated. On the basis of well rock electrical properties, experimental analyses, and depositional and structural patterns in the eastern region, we characterize the reservoir properties and identify the primary factors controlling shale gas accumulation. The results indicate that the Wujiaping shale is characterized by a high organic matter content, favorable pore types, high porosity, and a high content of brittle minerals, which are conducive to subsequent development and fracturing. A positive correlation is observed between the total organic carbon (TOC) content, porosity, brittle mineral content, and shale gas content. The TOC content is strongly correlated with the gas content (the correlation coefficient is 0.75). The high shale gas yield of the Wujiaping Formation is attributed to a combination of favorable sedimentary environments, pore conditions, roof and floor conditions, and fracturing capabilities. However, compared with the Longmaxi Formation in the Sichuan Basin, the Wujiaping Formation shale is characterized by a lower porosity, thinner shale, and deeper burial, posing challenges for exploration and development. In this study, criteria for evaluating Wujiaping Formation shale gas are established, and four favorable exploration areas are identified. Overall, the Permian Wujiaping Formation marine shale in the Longmen-Wushankan area holds promising exploration and development potential. Further exploration and an enhanced understanding of this formation will provide valuable guidance for future marine shale gas exploration and development in this area. [ABSTRACT FROM AUTHOR]

The Duvernay Formation in Canada is one of the major oil and gas source formations in the Western Canadian Sedimentary Basin, located at its deepest point. While it demonstrates promising development potential, challenges arise in the urgent need for integration of geology and engineering models, as well as in optimizing sweet spots, particularly as infill wells and pads become central operational objectives for the shale gas field. A lack of the geomechanical understanding of shale gas reservoirs presents a significant obstacle in addressing these challenges. To overcome this, we implemented data acquisition and prepared historical models and profiles, resulting in an extended high-resolution geological and reservoir property model with a fine grid system. Subsequently, a 3D full-field multi-scale geomechanical model was constructed for the main district by integrating seismic data (100 m), geological structures (km), routine logs (m), core data (cm), and borehole imaging (0.25 m), following a well-designed workflow. The predicted fracturability index (brittleness) ranges from 0.6 to 0.78, and a lower horizontal stress difference (STDIFF) is anticipated in the target formation, Upper Duvernay_D, making it a favorable candidate for hydraulic fracturing treatment. Post-analysis of the multi-disciplinary models and various data types provides guidelines for establishing a specific big database, which serves as the foundation for production performance analysis and aggregate sweet spot analysis. Fourteen geological and geomechanical candidate parameters are selected for the subsequent sweet spot analysis. This study highlights the effectiveness of multi-scale geomechanical modeling as a tool for the integration of multidisciplinary data sources, providing a bridge between geological understanding and future field development decisions. The workflows also offer a data-driven framework for selecting parameters for sweet spot analysis and production dynamic analysis. [ABSTRACT FROM AUTHOR]

Current shale gas well production capacity predictions primarily rely on analytical and numerical simulation methods, which necessitate extensive calculations and manual parameter tuning and produce lowly accurate predictions. Although employing neural networks yields highly accurate predictions, they can easily fall into local optima. This paper suggests a new way to use Cuckoo Search (CS)-optimized neural networks to make shale gas well production capacity predictions more accurate and to solve the problem of local optima. It aims to assist engineers in devising more effective development plans and production strategies, optimizing resource allocation, and reducing risk. The method first analyzes the factors influencing the production capacity of shale gas wells in a block located in western China through correlation coefficients. It identifies the main factors affecting the gas test absolute open flow as organic carbon content, small-layer passage rate, fracture pressure, acid volume, pump-in fluid volume, brittle mineral content in the rock, and rock density. Subsequently, we used the CS algorithm to conduct the global training of the neural network, avoiding the problem of local optima, and established a neural network model for predicting shale gas well production capacity optimized by the CS algorithm. A comparative analysis with other relevant methods demonstrates that the CS-optimized neural network model can accurately predict production capacity, enabling a more rational and effective exploitation of shale gas resources, which lower development costs and increase the economic returns of oil and gas fields. Compared to numerical simulation, SVM, and BP neural network algorithms, the CS-optimized BP neural network (CS-BP) exhibits significantly lower prediction error. Its correlation coefficient between predicted and actual values reaches as high as 0.9924. Verification experiments conducted on another shale gas well also demonstrate that, in comparison to the BP neural network algorithm, CS-BP offers superior prediction performance, with model validation showing a prediction error of only 0.05. This study can facilitate more rational and efficient exploitation of shale gas resources, reduce development costs, and enhance the economic benefits of oil and gas fields. [ABSTRACT FROM AUTHOR]

The evaluation methods for shale gas resources and the key parameters involved are diverse. The main research object of this article is the key parameters in shale gas resource evaluation, and this study aims to quantitatively evaluate the required key parameters for calculation, thereby improving the credibility of shale gas resource evaluation results. This article mainly analyzes the weight analysis of the key parameters used in the resource evaluation process, focusing on the analysis and determination of key parameters controlling the generation, enrichment, and preservation of shale gas. The key parameters are graded and evaluated layer by layer, and the common key parameters that participate in the determination are extracted. Based on the above analysis, a weight conversion model is proposed to quantitatively evaluate the actual importance of key parameters in resource evaluation. By combining statistical research, the partial correlation coefficients in the correlation coefficients are applied to estimate the resource quantities in the exploration field in order to quantitatively evaluate the credibility of the resource evaluation results. This article focuses on the weight assignment of key parameters for calculating the resource quantity of the Jiaoshiba shale gas field in the Fuling area of Chongqing and obtains different weight results for different parameters. Using this method to assign key parameter weights to the target block can provide reliable parameter support for shale gas resource evaluation and provide strong support for shale gas resource estimation. [ABSTRACT FROM AUTHOR]

This study aimed to increase the scale of oil‐based drilling cuttings (OBDCs) resource utilization in the ceramic industry. The sintering process and mechanism were explored based on the analysis of physicochemical properties, phase transitions, and microstructure. The results showed that (1) The main ceramic‐technological characteristics of the OBDC were determined, which belonged to high‐silica solid waste with a high Si–Al ratio and a low acid–base ratio of oxides. (2) The low meltability temperature of the OBDC could largely influence the determination of the sintering temperature range for ceramic products. (3) The chemical components OBDC provided were involved in the formation of molten phases, which could affect dimensional accuracy and mechanical properties. Meanwhile, the dolomite promoted the formation of closed pores and enhanced lightweight performance. (4) Before 800°C, dolomite decomposed and reacted with SiO2 to form silicate, and then a new feldspar crystal appeared. After 1000°C, orthoclase completely melted into the molten phase, only two phases of quartz and diopside existed in the material until 1150°C. When the temperature was higher than 1350°C, the glass transition of the phase was basically intensified. (5) In the analyzed scenarios, the results indicated OBDC can only be doped in low contents and degrades the ceramic material properties. [ABSTRACT FROM AUTHOR]

During the Rhuddanian–Aeronian interglacial period, global geological events such as glacial melting, synsedimentary volcanic activity, biological resurgence, and large-scale marine transgressions caused frequent fluctuations in paleoproductivity, climate changes, and sea level variations. These paleoenvironmental transitions directly influenced the development characteristics of shale lithofacies. This study investigates the Longmaxi Formation shale in the Changning area in the Southern Sichuan basin, focusing on 28 core samples from Well N1. Using scanning electron microscopy, QEMSCAN, TOC, XRD, and major and trace element analyses, we reconstructed the paleoenvironmental transitions of this period and explored their control over shale lithofacies types and mineral compositions. Four shale lithofacies were identified: carbonate rich lithofacies (CRF), biogenic quartz-rich lithofacies (BQRF), detrital clay-rich lithofacies (CRDF), and detrital quartz-rich lithofacies (DQRF). During the Rhuddanian period, rising global temperatures caused glacial melting and rapid marine transgressions. The low oxygen levels in bottom waters, combined with upwelling and abundant volcanic material, led to high paleoproductivity. This period primarily developed BQRF and CRF. Rich nutrients and abundant siliceous organisms, along with anoxic to anaerobic conditions, provided the material basis and preservation conditions for high biogenic quartz and organic matter content. High paleoproductivity and anoxic conditions also facilitated the precipitation of synsedimentary calcite and supplied Mg2+ and SO42− for the formation of iron-poor dolomite via sulfate reduction. From the Late Rhuddanian to the Mid-Aeronian, the Guangxi orogeny caused sea levels to fall, increasing water oxidation and reducing upwelling and volcanic activity, which lowered paleoproductivity. Rapid sedimentation rates, stepwise global temperature increases, and the intermittent intensification of weathering affected terrigenous clastic input, resulting in the alternating deposition of CRF, CRDF, and DQRF. Two favorable shale gas reservoirs were identified from the Rhuddanian–Aeronian period: Type I (BQRF) in the L1–L3 Layers, characterized by high TOC and brittleness, and Type II (DQRF) in the L4 Layer, with significant detrital quartz content. The Type I-favorable reservoir supports ongoing gas production, and the Type II-favorable reservoir offers potential as a future exploration target. [ABSTRACT FROM AUTHOR]