Gas Reservoirs Research Articles

Improving the classification of rock samples with diffusion probabilistic machine learning

Machine learning is a powerful data-driven technology for regression and classification tasks in numerous branches of science and technology. With probabilistic machine learning, we can approximate the probability density function of a given digital data set, unlocking the sampling of new and realistic data. We implement probabilistic machine learning as a statistical-based data augmentation tool to effectively improve the performance of a classifier on scarce data sets. Limited data are the norm in most practical situations, as is the case with core samples retrieved from unconventional oil and gas reservoirs. Obtaining and properly labeling rock sample images is a manual and time-consuming task. This leads to scarce data sets that make the lithologic classification of rock samples challenging. We illustrate the technology on images taken from well cores from the Argentinean Neuquén and Austral basins, where by introducing generated samples in the training stage of a machine-learning classifier, we achieve a 5% higher accuracy with respect to the baseline obtained using the same number of samples from the original data set. We reach these results by proposing a lightweight workflow that can be run on very limited hardware. Our workflow is an alternative to classical data augmentation strategies for dealing with incomplete information, such as geometric transformations.

Earthquake Growth Inhibited at Higher Coulomb Stress Change Rate at Groningen

AbstractGas extraction from the Groningen gas field resulted in significant induced seismicity. We analyze the magnitude‐frequency distribution of these earthquakes in space, time and in view of stress changes calculated based on gas production and reservoir properties. Previous studies suggested variations related to reservoir geometry and stress. While we confirm the spatial variations, we do not detect a clear sensitivity of b‐value to Coulomb stress changes. However, we find that b‐value correlates positively with the rate of Coulomb stress changes. This correlation is statistically significant and robust to uncertainties related to stress change calculation. This study thus points to a possible influence of stress change rate on the probability of the magnitude of induced earthquakes.

Genesis of the Wuchiapingian Formation Tuffs and Their Relationship with the Tectonic Background of the Kaijiang–Liangping Trough in the Northern Sichuan Basin

Controversy surrounds the forming time and tectonic background of the Kaijiang–Liangping Trough in the northern Sichuan Basin. The Wuchiapingian Formation, surrounding this Late Permian trough, contains tuffs, and industrial gas reservoirs have been discovered. However, the genesis of these tuffs, revealed by the drilling wells, remains unclear. In the present work, we analyzed the samples of sedimentary tuff from the core of the study area by macroscopic and microscopic analysis, combined with whole-rock major and trace element analysis, zircon U-Pb dating, and zircon trace element analysis, defining the genesis of the Wuchiapingian Formation tuffs around the Kaijiang–Liangping Trough, in an attempt to describe the initial tectonic context of the trough. The U-Pb ages of the tuffs measured in this study range from 255 to 259 Ma. They are slightly later than the activity of the Emeishan Large Igneous Province. Considering the trough’s distance from the center of the Emeishan Large Igneous Province and its location in the outer zone, it is more likely associated with acidic volcanic eruptions of the island arc. The arc was formed by the subduction activity of the Mianlue Ocean beneath the northern Yangtze Plate. In terms of the timing of activity and the tectonic position of the subduction zone, the Kaijiang–Liangping trough in the northern Sichuan Basin is more closely related to the closing of the Mianlue Ocean.

Pore-Scale Simulation of Deep Shale Gas Flow Considering the Dual-Site Langmuir Adsorption Model Based on the Pore Network Model.

As a key resource in the oil and gas sector, shale gas development profoundly influences the advancement of the global energy industry. Deep shale gas reservoirs, typically found at depths exceeding 3500 m, represent a significant portion of total shale gas reserves. Currently, pore network models primarily simulate middle and shallow shale gas, insufficiently addressing the unique challenges posed by high-temperature and high-pressure conditions in deep shale gas formations. There is an urgent need to explore the microscale flow dynamics of deep shale gas. In this work, we use the pore network model to simulate the flow dynamics of deep shale gas, particularly under nanoconfinement conditions. The simulation integrates adsorption, slip flow, Knudsen diffusion, and bulk flow phenomena. Utilizing the dual-site Langmuir adsorption model tailored for high-temperature and high-pressure conditions enhances the accuracy of gas conductivity calculations for the adsorbed phase, thereby reflecting the specific characteristics of deep shale gas reservoirs. Moreover, this research investigates the flow characteristics of deep shale gas under varying sensitivity parameters, such as water saturation, temperature, and pressure. It explores methane flow dynamics, focusing on effective diffusion coefficients and permeability. The modified approach to calculating adsorption phase conductivity using the dual-site Langmuir adsorption model accurately captures the adsorption behaviors and characteristics of deep shale gas reservoirs.

Research on the Injection–Production Law and the Feasibility of Underground Natural Gas Storage in a Low-Permeability Acid-Containing Depleted Gas Reservoir

Depleted gas reservoirs are important places for the rebuilding of gas-storage reservoirs. In order to demonstrate the feasibility of constructing and operating such underground gas storage, a low-permeability gas-storage seepage model considering fracture development was developed and established. The model was solved using semi-analytical methods, and the pressure–response characteristics during natural gas injection were analyzed. The impact of gas injection volume on formation pressure has been clarified, and the calculation method for ultimate injection pressure has been determined. Additionally, through numerical simulation methods, the migration law of acidic gas during gas injection, the variation law of produced acidic gas concentration, and the main control factors affecting the concentration of the produced acidic gas were studied. Furthermore, measures to reduce the concentration of the acidic gas produced were proposed. Finally, injection and production plans were designed for typical depleted acidic gas reservoirs, simulating the operation of gas storage for 12 cycles. The results indicate that the quality of natural gas produced in the third cycle can meet the Class II standard for commercial natural gas. Through this study, the feasibility of constructing gas-storage facilities for acidic depleted gas reservoirs has been demonstrated, and injection and production strategies for this type of gas reservoir have been proposed.

A petrophysically driven seismic inversion method for the total organic carbon content of source rocks

Organic carbon content is the main index for evaluating organic matter abundance of source rocks, and it is still difficult to quantitatively predict total organic carbon (TOC) in source rocks based on seismic data. The study of seismic fluid identification driven by petrophysics can help to understand the fluid characteristics and distribution patterns of subsurface oil and gas reservoirs. First, this paper clarifies the sweet spot parameters (parameters characterizing hydrocarbon enrichment) and sensitive elastic parameters (a parameter characterizing the nature of an ideal elastic body) of source rocks through theoretical petrophysical modeling. Next, the paper establishes the relationship between sensitive elastic parameters and sweet spot parameters TOC and constructs a statistical petrophysical model that can characterize the relationship between the two on this basis. And then we construct the joint distribution of TOC and elastic impedance through the Bayesian theoretical framework to obtain the maximum posterior probability estimate as the final TOC inversion results of source rocks. Our method successfully predicts the spreading of high-quality source rocks in the Wen4 Section of Lufeng 13 Subsag, and the inversion results are within an uncertainty range of ±14 m for well data, which proves the reliability of the method. The prediction results show that the organic matter abundance of source rocks in the Wen4 Section is high, and the organic carbon content is generally higher than 2%, which provides a reliable basis for the further implementation of the resource scale of the depression and the clarification of the hydrocarbon-rich area, which provides technical support for the evaluation of the source rocks of the new depression in the new area.

Sedimentary characteristics and reservoir architecture of a lacustrine mixed carbonate/siliciclastic system: the lower member of the ShangGanchaigou Formation, Neogene, in the western Qaidam Basin, China

Lacustrine mixed carbonate/siliciclastic sediment is an important type of oil and gas reservoir with significant potential. Although previous studies have investigated the sedimentary characteristics of the mixed depositional system in numerous oil and gas-bearing basins worldwide, a detailed sedimentary architecture model is still lacking for guiding reservoir characterization at the hydrocarbon reservoir scale. In this paper, a typical lacustrine mixed carbonate/siliciclastic sedimentary system, preserved in the lower member of the ShangGanchaigou Formation, Neogene, in the western Qaidam Basin, Western China, was deeply investigated based on well logging data from 640 wells, 438 m of cores from 3 core wells, and outcrop studies. The results demonstrate that 1) seven types of architecture elements, namely, distributary channel, channel mouth bar, distal bar, sheet-like sand, shallow water mud, algal mound, and marl flat characterized by different lithofacies associations, were recognized based on core and well logging data. 2) The lacustrine mixed carbonate/siliciclastic depositional system can be divided into three facies belts. Along the lakeward direction, the proximal facies belt is dominated by delta front deposits and characterized by gradually downstream bifurcating distributary channels and associated lateral amalgamated delta lobes. The middle facies belt is characterized by isolated and small-scale delta lobes and inter-lobe deposits, including sheet-like sand, small-scale algal mounds, and marl flats, and the distal facies belt is a combination of large-scale algal mounds and marl flats. 3) Within a depression, short-term base-level cycles controlled the facies belt transition, and the proximal, middle, and distal facies belts formed under relatively low, middle, and high base-level conditions, respectively. 4) The scale and connectivity of reservoirs gradually decreased from the proximal to the distal belt.

The foresight methodology for transitional shale gas reservoirs prediction based on a knowledge graph

The sedimentary environment in the eastern Ordos area of China is complex and contains a large number of transitional facies environments. Yet, there are many characteristics such as large vertical lithology changes, complex lateral sedimentary environment changes, small monolith thickness and large organic matter content changes, which lead to large uncertainty in the prediction of favorable areas for transitional shale gas. As the intricate reservoirs continue to unfold, the conventional linear prediction methods find themselves facing an arduous path to meet the demands of development. The ever-evolving complexity of these reservoirs has outpaced the capabilities of these traditional approaches. It becomes apparent that a more comprehensive and adaptable approach is necessary to navigate the intricacies of these reservoirs and unlock their hidden potential. Therefore, we put forward a method of introducing knowledge graph into transitional shale gas reservoir prediction in the eastern Ordos region by using big data technology. Because artificial intelligence big data relies heavily on data tags, it is particularly important for the construction of tags. Firstly, a top-down knowledge graph in the field of reservoir prediction is constructed to determine the key parameters used in prediction, namely porosity, total organic carbon and brittleness index. Secondly, the decision tree knowledge graph optimization label is constructed in a bottom-up way. The key parameter of this prediction is the knowledge graph obtained according to the professional knowledge of reservoir prediction, so as to optimize the school label of U-net and reduce the workload of artificial judgment. The results of the combination of the two methods are applied to 11 wells in Daji area of Ordos, and the experimental results are consistent with the actual situation of the reservoir. Based on the foundation of theoretical knowledge, this method enhances the efficiency and accuracy of interpretation and evaluation. It provides fundamental and technical support for the selection of favorable areas in shale gas exploration and the evaluation of exploration and development prospects, particularly in transitional shale gas areas, which is innovative and advanced in the field.

Hydrocarbon charge history of deeply buried clastic reservoirs in the Bozi area of the Kuqa Depression, western China: implications for deep and ultra-deep petroleum exploration

Significant progress has recently been made in deep and ultra-deep oil and gas exploration globally, demonstrating enormous exploration potential of the deep and ultra-deep strata. However, the accumulation and preservation pattern of deep and ultra-deep oil and gas remains poorly understood, greatly impeding further petroleum exploration and development in the deep and ultra-deep strata. By taking the Bozi deep and ultra-deep condensate gas reservoirs in the Kuqa Depression, western China as an example, we attempt to reconstruct the hydrocarbon charge history in such deep reservoirs via an integrated investigation involving quantitative grain fluorescence, fluid inclusion petrography and microthermometry, micro-fluorescence spectroscopy, laser Raman spectroscopy, PVTx modelling, and basin modelling. The results show that: (1) The Bozi deep and ultra-deep reservoirs contain one group of gas inclusion assemblage, and two groups of oil inclusion assemblages, with one being characterized by near yellowish-whitish and blue-whitish diphasic or triphasic oil inclusions, and the other being featured by bright blue diphasic oil inclusions; (2) The first oil charge occurred during the Early Neogene (6.5–5.5 Ma), and the second oil charge occurred during the Late Neogene (4.4–3.5 Ma), under normal hydrostatic pressure or slightly weak overpressure; and (3) The gas charge occurred during the Pleistocene (∼1.6 Ma), with a corresponding reservoir pressure coefficient of approximately 1.7, transforming the reservoir fluid phase state from black oil or volatile oil to condensate gas. Our findings highlight that aside from the present burial depth, a favorable burial history model is crucial for the preservation of liquid hydrocarbons in deep and ultra-deep reservoirs. The occurrence of liquid hydrocarbons in the Bozi deep and ultra-deep condensate gas reservoirs with depths over 7,000 m is benefited from a prolonged period (>100 Ma) of shallow burial and a late-stage (since 10 Ma) rapid subsidence.

Deciphering minerals in reservoir rocks as natural catalysts for in-situ methane-to-hydrogen conversion via electromagnetic heating

Electromagnetic (EM)-assisted catalytic heating for in-situ hydrogen generation directly from petroleum reservoirs is an emerging method for decarbonizing petroleum industry and facilitating energy transition. Lab-scale experiments have shown that hydrogen generated from methane cracking in the presence of sandstone via EM heating can reach up to a concentration of 91 mol.% at 668 °C. However, the role of various minerals in reservoir rocks during this process remains poorly understood. This study aims to decipher the natural catalytic effects of minerals of reservoir rocks, such as quartz, kaolinite, illite, chlorite, etc., in catalyzing methane conversion to hydrogen under EM irradiation. Our findings demonstrate that kaolinite exhibits the strongest catalytic activity, starting to generate hydrogen at 331 °C and achieving a 73% methane conversion at 450 °C, while chlorite and albite also showing notable activity with hydrogen being generated below 500 °C. Furthermore, this study quantifies the catalytic contributions of metal oxides, Na+ in albite, Fe2+ and Mg2+ in chlorite and illite, and Al3+ in kaolinite, in promoting methane conversion to hydrogen. By deciphering the catalytic role of minerals and metal oxides, this research offers crucial insights for future optimization of field-scale H2 production from gas reservoir by leveraging the minerals of reservoir rocks as natural catalysts.

Current Status of Research on Seepage Mechanism in Tight Sandstone Gas Reservoirs

China's tight sandstone gas reservoirs have a large amount of resources, which is an important part of future energy. At present, one of the main problems facing the production of tight sandstone gas reservoirs is water production, and the water production of gas wells is a key influence factor restricting the stable and increased production of gas reservoirs. Firstly, the research status of reservoir characteristics of tight sandstone gas reservoirs is summarized, then the seepage mechanism of tight sandstone gas reservoirs is analyzed, and finally the relationship between gas and water in tight sandstone gas reservoirs is reviewed, which provides a basis for further research on the seepage mechanism of tight sandstone gas reservoirs and the law of gas and water production.

Research Progress of Three-dimensional Geological Modeling and Multi-field Coupling of Fractured Oil and Gas Reservoirs

Fractured oil and gas reservoirs play an important role in oil and gas exploration and development due to their complex fracture network structure. As the main fluid channel in the reservoir, fractures have a significant impact on the migration, accumulation and exploitation efficiency of oil and gas. This paper summarizes the key geological characteristics of fractured reservoirs, including fracture types, distribution rules and main controlling factors of fracture development, and discusses the influence of fractures on reservoir physical properties. Furthermore, the deterministic and stochastic modeling methods of three-dimensional geological modeling of fractured reservoirs and the latest progress of discrete fracture network modeling technology are introduced in detail. In addition, this paper also discusses in detail the application of multi-field coupling model in the numerical simulation of fluid flow in fractured reservoirs, including continuous medium model and discrete medium model, and their advantages and disadvantages in simulating fluid flow in fractured reservoirs. Finally, this paper summarizes the research progress of multi-physics coupling model of fractured reservoirs, and points out the direction and challenges of future research. Through these studies, it can provide theoretical support and technical guidance for oil and gas exploration and development, in order to achieve more effective development and management of fractured reservoirs.

Exploring comparative heterogeneity management for precise water saturation assessment in carbonate formations: Dean-Stark measurements and beyond

Accurate determination of water saturation is a critical aspect of reservoir characterization and development potential of a hydrocarbon field. The inherent heterogeneity in carbonate reservoirs significantly influences the Archie equation coefficients and, consequently, water saturation calculations. In this study, 160 direct core sample water saturation measurements using the Dean-Stark method have been used. The primary goal was to identify the most suitable reservoir heterogeneity management approach for water saturation calculation. The research focuses on the Dalan and Kangan formations (equivalent to Khuff Formation), known as some of the most hydrocarbon-rich (gas) reservoirs globally, located in the western part of the Persian Gulf. To manage reservoir heterogeneity, we employed various techniques, including Winland R35, flow zone indicator, Lucia, pore types, and electrofacies, utilizing porosity and permeability core data, thin section studies, and well-logging data to classify the studied intervals into more homogeneous categories. Subsequently, we measured Archie parameters and, for the first time, water saturations derived from Dean-Stark measurements were compared with Archie saturations from various heterogeneity management methods. Additionally, the influence of geological and petrophysical parameters on the accuracy of water saturation calculations in different rock types is discussed. Our results highlighted the significance of geometrical attributes of pore types, pore throat radius, and permeability as key factors affecting the precision of water saturation calculations. Moreover, our investigation revealed that Lucia's rock typing methodology exerted a substantial influence on the control of permeability and the distribution of water saturation within the reservoir. Our analysis revealed that the electrofacies method provided the most precise estimates for water saturation, with a mean difference of 0.07 (v/v) units compared to the Dean-Stark method. Subsequently, the accuracy of predicted water saturation in rock types determined by the Lucia method, with a mean error of 0.09 (v/v), ranked second among the rock typing methods. Winland R35 and flow zone indicator methods exhibited the highest uncertainty in water saturation estimation, with mean differences of 0.23 and 0.21 (v/v), respectively, compared to the Dean-Stark method.

Shale gas leakage and fault activation: Insight from the 2021 Luxian MS 6.0 earthquake, China

In the region of large gas fields, extensive research has been conducted on earthquakes induced by industrial production in shale gas fields. However, limited attention has been given to the impact of post-earthquake events on shale gas reservoir leakage and fault activation. The Luxian MS 6.0 earthquake, which occurred on 16 September 2021 in the Luzhou shale gas field, has raised concerns about post-earthquake shale gas leakage. Post-earthquake measurements of soil gases (Rn, CO2, CH4, and H2) and isotopic analyses (δ13CCO2, δ13CCH4 and δDCH4) in the Luzhou shale gas field area reveal that the Huayingshan fault zone, a natural pathway for shale gas leakage, was not activated by the Luxian earthquake and did not exhibit any further shale gas leakage after the 2021 earthquake. Furthermore, the seismogenic fault, which was impacted by the earthquake, did not damage the shale gas reservoir, causing shale gas leakage. This study provides an important foundation for future research on shale gas extraction and seismic activity in the region.

Multi-scale model for evaluating stress fluctuation in shale gas reservoirs considering geomechanical heterogeneity

In this article, a numerical model considering multi-scale flow and heterogeneity of shale reservoirs is developed to analyze the spatiotemporal evolution of the stress field in shale gas production. After considering the geomechanical heterogeneity, the variation in the local rock mechanical parameters of the reservoir, and the increase in the effective stress of the reservoir will cause local stress fluctuations. In the hydraulic fracture control area, the average stress fluctuation coefficient is higher, indicating a stronger “stress heterogeneity.” When the homogeneity increases from 5 to 100, the fluctuation range of the minimum horizontal principal stress increases by 28.89 MPa, and the fluctuation range of the principal stress difference increases by 7.35 MPa. The presence of natural fractures can significantly impact the coupled hydraulic-mechanical processes of the reservoir, increasing the number of high-speed permeation channels penetrating the system. The greater the density and permeability, the smaller the minimum horizontal principal stress and the larger the principal stress difference. The angle of natural fractures directly influences the direction of stress drop, with an average minimum horizontal principal stress occurring when the angle of natural fractures is at 60°/120°.

Depositional and diagenetic controls on the reservoir quality of marginal marine sandstones: An example from the Early Devonian subbat member, jauf formation, northwest Saudi Arabia

The reservoir quality of marginal marine sandstones can vary significantly across different depositional lithofacies. This variation is primarily due to differences in depositional processes and subsequent diagenetic alterations occurring during various stages of burial. To address this issue, this study focuses on the Early Devonian Subbat sandstones of the Jauf Formation, which serve as an important analogue for subsurface gas reservoirs and have potential for CO2 sequestration. An integrated approach was employed, including field observations, petrography, geochemical analyses, and petrophysical analyses, to investigate the impact of depositional and diagenetic processes on reservoir quality. The findings indicate that the sandstones range from poorly to well sorted, very fine to medium-grained arkosic and quartz arenites that were deposited in a range of environments including shoreface-to-offshore transition zones, wave-dominated deltas, fluvial and tidal estuarine channels. The sandstones experienced both shallow and deep burial diagenesis, while key diagenetic events affecting reservoir quality include compaction, carbonate cementation, the formation of authigenic clays (kaolinite, illite, and chlorite), quartz overgrowth, and the dissolution of unstable feldspar and mica grains. Authigenic pore-filling cements and grain-coating clays significantly influence reservoir quality. The effect of quartz cementation was minimal where illite and/or chlorite coatings are well-developed. Mechanical compaction is more pronounced in the shoreface-to-offshore transition compared to the estuarine channels likely due to the higher detrital matrix content (21.7–35%, avg. 26.7%). The well-sorted fluvial to estuarine channel sandstones exhibit the best reservoir quality, with porosity ranging from 15.9% to 25.5% (average 20.4%) and permeability between 433.8 mD and 1261.2 mD (average 720 mD). This high reservoir quality is attributed to the low detrital matrix content (0–1%, average 0.2%) and limited pore-filling cements. In comparison, the moderately sorted, wave-dominated delta sandstones have lower porosity (5.3–11.2%, average 8.2%) and permeability (17.8–80 mD, average 42.8 mD), despite a relatively higher detrital matrix content (0–11.5%, average 2.8%). The poorly sorted shoreface-to-offshore transition sandstones exhibit the lowest reservoir quality, with porosity ranging from 1% to 2% (average 1.5%) and permeability between 0.3 and 1.1 mD (average 0.7 mD). These variations in reservoir quality among different depositional facies are primarily linked to depositional factors (sorting and detrital clay matrix) and shallow to deep burial diagenetic processes (compaction and cementation). A comprehensive understanding of these processes can enhance reservoir quality prediction in the Jauf Formation and similar reservoirs elsewhere.

Development and performance evaluation of hydrophobic association plugging agents for sealing formation prior to cementing

This study introduces a novel blocking agent composed of polymerized hydrophobic particles to address the challenge of sealing formations with heterogeneous permeability. These particles display high viscosity and adsorption capabilities, essential for sealing highly permeable formations effectively. Hydrophobic associative polymers (AMSN) were prepared using free radical micellar polymerization, grounded in hydrophobic association principles and molecular design. Optimal monomer ratios and synthesis procedures were identified through the observation of the polymers’ apparent viscosity in aqueous solutions. Characterization of the polymers involved Fourier transform infrared spectroscopy, thermogravimetric analysis, and fluorescence analysis to assess their temperature and salt resistance, reduction in filtrate loss, and blocking abilities. The polymers, containing hydrophobic groups at 300 mg/L concentrations, demonstrated excellent temperature resistance, maintaining 50% of their original viscosity at 95 °C, and sustained effectiveness in 50 g/L salt solutions, surpassing conventional polymers like HPAM. The sealing effect of this hydrophobic conjugated polymer on cracks with different openings can effectively solve the leakage problem. It addresses the need for effective plugging in heterogeneous formation with uncertain leak channel dimensions. Therefore, this study is of great significance for solving cementing leakage, especially for oil and gas reservoir protection in non-homogeneous reservoirs.

Sensitivity Analysis of Depth-Controlled Oriented Perforation in Horizontal Wells Based on the 3D Lattice Method

The main method used to exploit unconventional oil and gas reservoirs involves multi-cluster perforation combined with hydraulic fracturing in horizontal wells. However, as the use of this technology has expanded, challenges like reduced perforation efficiency and elevated fracture initiation pressure have surfaced. The depth-controlled oriented perforation technique helps achieve uniform fracture initiation, enhance efficiency, and lower initiation pressure. In this study, a hydraulic fracturing fluid–solid coupling model at the perforation scale was established using the 3D lattice method to compare the near-wellbore fracture morphologies of depth-controlled oriented perforation, spiral perforation, and oriented perforation. Additionally, this study analyzes the effects of injection rate, reservoir elastic modulus, and horizontal stress difference on the fracture morphology and initiation pressure of depth-controlled oriented perforation. This study clarifies the applicability of depth-controlled oriented perforation in different types of reservoirs for the first time. The results indicate that intermediate fractures between spiral and oriented perforations are hindered, while depth-controlled oriented perforation ensures uniform fracture initiation. In the injection rate range of 0.144 to 0.360 L/min, an increase in injection rate accelerates the rise of fluid pressure within the perforations, leading to an increase in fracture initiation pressure. Therefore, excessively high injection rates are unfavorable for fracture initiation. Through depth-controlled oriented perforation, long and singular fractures can be formed in reservoirs with significant horizontal stress differences and high elastic moduli.

A Study on the Breakthrough Pressure of Porous Rock Formations in Gas Storage Reservoirs

Breakthrough pressure of natural gas in rock is an important evaluation parameter in gas reservoir development. In this study, experimental measurements of porosity and permeability of the caprock core were carried out. A digital core model was obtained by body rendering of rock CT (Computed Tomography) slices using Avizo software. Then, the grid model was imported into Fluent software for a numerical simulation of natural gas breakthrough pressure in the core. The innovations of this paper include (1) an accurate calculation method of cap breakthrough pressure based on the VOF method; (2) the method performs a perceptual analysis of average pore radius, wettability, roughness height, and viscosity ratio.

Rapid identification of an effective bauxite gas reservoir by principal component analysis.

In recent years, industrial gas flow has been obtained from the bauxite gas reservoir in the southwestern Ordos Basin, which has made the identification of aluminium-bearing rock reservoirs a popular topic. To accelerate the exploration and development of this type of gas reservoir, major element testing, rock thin section identification and principal component analysis (PCA) were conducted, and a method for rapid and accurate identification of bauxite reservoirs via conventional logging was established. The test results clearly revealed the vertical stratification of major elements and three lithologies in the aluminium (Al)-bearing rock series in the study area. The log response characteristics of effective gas reservoirs were summarized, providing a basis for subsequent research on identifying effective bauxite reservoirs via mathematical dimensionality reduction of logging curves. The porosity comparison of strata with different lithologies suggests that dissolution pores are more developed in Al-rich layers, providing insight for identifying effective reservoirs by Al2O3 content. On the basis of the above findings, a lithological identification chart of Al-bearing rock series was established via principal component analysis (PCA), and an effective bauxite reservoir logging identification model based on Al2O3 content prediction was developed. The results show that using the dimensionality reduction method for principal component analysis of logging curves with overlapping information can avoid model distortion caused by multicollinearity. The research results can be used to identify bauxite reservoirs quickly and accurately without other test data.