Unconventional Oil Resources Research Articles

Comprehensive Study on Microscopic Pore Structure and Displacement Mechanism of Tight Sandstone Reservoirs: A Case Study of the Chang 3 Member in the Weibei Oilfield, Ordos Basin, China

With the continuous growth in global energy demand, research and development of unconventional oil and gas reservoirs have become crucial in the field of energy. This study focuses on the Chang 3 reservoir of the Yanchang Formation in the Ordos Basin, Weibei Oilfield, China. This reservoir is a typical tight sandstone reservoir, and its microscopic pore structure and displacement mechanism are essential for the efficient development of tight oil. However, the reservoir faces challenges such as complex microscopic pore structures and unclear displacement mechanisms, which hinder the efficient development of tight oil. In light of these challenges, through various studies including core observation, high-pressure mercury injection tests, water flooding experiments, oil-water two-phase relative permeability measurements, and stress sensitivity experiments, it was found that the Chang 3 reservoir exhibits strong microscopic heterogeneity. The pore-throat distribution characteristics mainly present two types: single peak and double peak, with the double peak type being predominant. The reservoir was classified and evaluated based on these characteristics. The improved injection ratio and properties enhance oil displacement efficiency, but an increase in irreducible water saturation has a negative impact on efficiency. The stress sensitivity of the reservoir fluctuates between weak and strong, with permeability being sensitive to net confining pressure. It is recommended to pay particular attention to the stress-sensitivity characteristics during reservoir development. The research results provide a scientific basis for the optimized development of tight oil reservoirs in this region, promote the sustainable development of unconventional oil and gas resources, and have significant theoretical and practical implications.

Application of geophysical well logs in solving geologic issues: Past, present and future prospect

Geophysical well logs are widely used in geological fields, however, there are considerable incompatibilities existing in solving geological issues using well log data. This review critically fills the gaps between geology and geophysical well logs, as assessed from peer reviewed papers and from the authors’ personal experiences, in the particular goal of solving geological issues using geophysical well logs. The origin and history of geophysical logging are summarized. Next follows a review of the state of knowledge for geophysical well logs in terms of type of specifications, vertical resolution, depth of investigations and demonstrated applications. Then the current status and advances in applications of geophysical well logs in fields of structural geology, sedimentary geology and petroleum geology are discussed. Well logs are used in structural and sedimentary geology in terms of structure detection, in situ stress evaluation, sedimentary characterization, sequence stratigraphy division and fracture prediction. Well logs can also be applied in petroleum geology fields of optimizing sweet spots for hydraulic fracturing in unconventional oil and gas resource. Geophysical well logs are extending their application in other fields of geosciences, and geological issues will be efficiently solved via well logs with the improvements of advanced well log suits. Further work is required in order to improve accuracy and diminish uncertainties by introducing artificial intelligence. This review provides a systematic and clear descriptions of the applications of geophysical well log data along with examples of how the data is displayed and processed for solving geologic problems.

Results of Quantitative Estimation of Unconventional Oil Resources of the Russian Federation

Abstract —The estimation results of the initial total unconventional resources of hydrocarbon in Domanik type sediments, the Khadum and Bazhenov formations are provided. The reasonability of estimating hydrocarbon resources in these deposits by the volumetric method is substantiated. The stratigraphic interval of their distribution is given. The technique of oil and gas geological zoning based on the mapping of structural and facies zones, the degree of catagenetic transformation of organic matter, and the boundary values of the thickness of carbonaceous rocks in the section is described. The criteria for the allocation of pay intervals that make up the effective part of the section are determined. The choice of parameters such as porosity coefficient, oil recovery coefficient, oil saturation coefficient, correction factor and oil density is justified. For each complex of deposits, adjustments related to the features of the geological structure of the estimation targets, the conditions of their occurrence and the degree of geological and geophysical study have been introduced into the estimation of total geological resources. The volumes of total geological and recoverable resources of unconventional hydrocarbon sources for the Volga– Ural, Timan–Pechora, Black Sea–North Caucasus, West Siberian and Lena–Tunguska oil and gas provinces are given. The conducted research has rationalized extensive resources, the recovery of which can compensate for the decrease in oil volumes from traditional deposits.

A Powerful Prediction Framework of Fracture Parameters for Hydraulic Fracturing Incorporating eXtreme Gradient Boosting and Bayesian Optimization

In the last decade, low-quality unconventional oil and gas resources have become the primary source for domestic oil and gas storage and production, and hydraulic fracturing has become a crucial method for modifying unconventional reservoirs. This paper puts forward a framework for predicting hydraulic fracture parameters. It combines eXtreme Gradient Boosting and Bayesian optimization to explore data-driven machine learning techniques in fracture simulation models. Analyzing fracture propagation through mathematical models can be both time-consuming and costly under conventional conditions. In this study, we predicted the physical parameters and three-dimensional morphology of fractures across multiple time series. The physical parameters encompass fracture width, pressure, proppant concentration, and inflow capacity. Our results demonstrate that the fusion model applied can significantly improve fracture morphology prediction accuracy, exceeding 0.95, while simultaneously reducing computation time. This method enhances standard numerical calculation techniques used for predicting hydraulic fracturing while encouraging research on the extraction of unconventional oil and gas resources.

Research Progress on CO2 Capture, Utilization, and Storage (CCUS) Based on Micro-Nano Fluidics Technology

The research and application of CO2 storage and enhanced oil recovery (EOR) have gradually emerged in China. However, the vast unconventional oil and gas resources are stored in reservoir pores ranging from several nanometers to several hundred micrometers in size. Additionally, CO2 geological sequestration involves the migration of fluids in tight caprock and target layers, which directly alters the transport and phase behavior of reservoir fluids at different scales. Micro- and nanoscale fluidics technology, with their advantages of in situ visualization, high temperature and pressure resistance, and rapid response, have become a new technical approach to investigate gas–liquid interactions in confined domains and an effective supplement to traditional core displacement experiments. The research progress of micro–nano fluidics visualization technology in various aspects, such as CO2 capture, utilization, and storage, is summarized in this paper, and the future development trends and research directions of micro–nano fluidics technology in the field of carbon capture, utilization, and storage (CCUS) are predicted.

Preparation and performance evaluation of the slickwater using novel polymeric drag reducing agent with high temperature and shear resistance ability

Slickwater fracturing fluids are widely used in the development of unconventional oil and gas resources due to the advantages of low cost, low formation damage and high drag reduction performance. However, their performance is severely affected at high temperatures. Drag reducing agent is the key to determine the drag reducing performance of slickwater. In this work, in order to further improve the temperature resistance of slickwater, a temperature-resistant polymeric drag reducing agent (PDRA) was synthesized and used as the basis for preparing the temperature-resistant slickwater. The slickwater system was prepared with the compositions of 0.2 wt% PDRA, 0.05 wt% drainage aid nonylphenol polyoxyethylene ether phosphate (NPEP) and 0.5 wt% anti-expansion agent polyepichlorohydrin-dimethylamine (PDM). The drag reduction ability, rheology properties, temperature and shear resistance ability, and core damage property of slickwater were systematically studied and evaluated. In contrast to on-site drag reducing agent (DRA) and HPAM, the temperature-resistant slickwater demonstrates enhanced drag reduction efficacy at 90 °C, exhibiting superior temperature and shear resistance ability. Notably, the drag reduction retention rate for the slickwater achieved an impressive 90.52% after a 30-min shearing period. Additionally, the core damage is only 5.53%. We expect that this study can broaden the application of slickwater in high-temperature reservoirs and provide a theoretical basis for field applications.

Study on the characteristic of asphaltene-wax co-precipitation during gas injection of unconventional gas condensate reservoirs

The intensification of energy shortage has accelerated the development of unconventional oil and gas resources, during which complex problems of organic solid precipitation often occur. The precipitation behavior of organic solid such as asphaltene and wax play an important role in the optimization of reservoir production. However, there is still a lack of comprehensive understanding of the precipitation mechanism and interaction between asphaltene and wax, especially under high temperature and pressure. A self-designed precipitation apparatus based on backscattered light was utilized to achieve this objective. The effects of temperature range 30–120 ℃, pressure range 5–85 MPa, gas-oil ratio of 150，300 and 500 sm3/sm3 and injection gas of CH4, CO2 and N2 on organic solid precipitation in condensate oil-gas system were studied by physical simulation. The results revealed that asphaltene precipitated separately at high temperature, and asphaltene and wax co-precipitated at low temperature. Based on the observed precipitation behavior, a co-precipitation mechanism of asphaltene and wax under high-pressure conditions was proposed: Asphaltene particles precipitated first, providing nucleation sites for wax absorption, growth, and cross-linking as the pressure decreased. Moreover, the depressurization induced phase separation during oil and gas production resulted in the extraction of light components, reducing the solubility of wax and exacerbating reservoir damage caused by the precipitation of organic solid. Increasing the gas-oil ratio led to higher amounts of organic solid precipitation and shifted the pressure at which precipitation occurred. Furthermore, the miscibility of injection medium and condensate oil will also significantly affect organic matter precipitation, and the potential damage to the reservoir can be shown as follows: N2＞CO2＞CH4.

An Overview of How the Petrophysical Properties of Rock Influenced After Being Exposed to Cryogenic Fluid

Exposure to cryogenic liquids can significantly impact the petrophysical properties of rock, affecting its density, porosity, permeability, and elastic properties. These effects can have important implications for various applications, including oil and gas production and carbon sequestration. Cryogenic liquid fracturing is a promising alternative to traditional hydraulic fracturing for exploiting unconventional oil and gas resources and geothermal energy. This technology offers several advantages over traditional hydraulic fracturing, including reduced water consumption, reduced formation damage, and a reduced risk of flow-back fluid contamination. In this study, an updated review of recent studies demonstrates how the thermal shock caused by the cryogenic liquid during the fracturing process substantially affects the rock's physical properties. Additionally, changes in permeability, porosity, and pore structure brought about by cryogenic treatments are highlighted. This work aims to draw attention to the studies that deal with the effect of thermal shock on rock petrophysical properties and establish the ideal conditions for employing cryogenic liquids in these contexts. Simulation studies, laboratory trials, and field application cases have been undertaken to assess the efficacy of cryogenic liquid fracturing technology. These investigations have provided important insights into the physical and mechanical impacts of thermal shock on rock and the performance of cryogenic liquid fracturing in real-world situations.

Numerical Simulation Analysis of Wellbore Integrity and Casing Damage in High-Temperature Injection and Production of Shale Oil

Shale oil represents a relatively new form of unconventional oil and gas resource, and the extensive exploration and development of shale oil resources carry significant implications for China’s oil and gas supply and demand dynamics. At present, within the realm of low-maturity shale oil extraction technologies, the reservoir must be subjected to elevated temperatures ranging between 400 to 60 °C. Prolonged exposure of wellbores to such high temperatures can result in a substantial decrease in cement strength, the formation of microcracks due to cement cracking, and damage stemming from thermal stresses on the casing. Casing damage stands out as a prominent factor contributing to wellbore integrity failures and well shutdowns within the context of shale oil development. Given the limited natural energy reservoirs of shale oil formations, it becomes necessary to supplement the reservoir’s energy during the development process. Furthermore, shale oil exhibits high viscosity and poor flowability, and conventional water injection methods yield limited efficacy. This situation can induce significant shifts in the stress field and rock mechanical parameters, potentially activating specific formations and complicating the load dynamics on the casing. Consequently, the risk of failure increases. In light of these considerations, this study uses numerical simulations to study the integrity of high-temperature injection and production wellbores in shale oil and aims to encompass a comprehensive evaluation and analysis of the principal factors that influence casing damage, the fluctuations in thermal stress, and the yield strength of various steel grades of casings exposed to alternating stress conditions. Subsequently, this paper developed a model for simulating the temperature and pressure within shale oil and steam injection wellbores to support engineering design analysis. The research results indicate that the application of pre-stress results in a significant increase in stress at the casing pipe head while causing a noticeable decrease in stress within the pipe wall. When N80 casing is used, the entire casing experiences thermal stresses surpassing the casing’s yield limit. Stress concentration may arise at both ends of the external seal, potentially leading to casing contraction, shear failure, and, under non-uniform stress conditions, casing bending deformation. The temperature of steam injection significantly influences the temperature field of the casing wall, with stress values experiencing a marked reduction when the steam injection temperature decreases from 350 °C to 200 °C, underscoring the substantial impact of temperature on casing thermal stress. As the steam injection process advances along with injection-production cycles, shear stresses at the interface can exceed the bond strength, resulting in relative slippage between the cement and the casing. The bonding force between the wellbore and the cement primarily depends on the interface’s friction, particularly in the context of friction during wellhead lifting. This study endeavors to determine rational injection and production parameters under varying conditions, optimize completion methods, reduce casing damage, and extend the casing’s operational life; it aims to offer critical technical support for the safe and efficient development of shale oil resources.

Novel polymeric organic gelator as lost circulation material for oil-based drilling fluids

With the exploitation of unconventional oil and gas resources towards deep and ultra-deep formations, oil-based drilling fluids (OBDFs) with white oil as a base oil have been increasingly employed in China to achieve safe, efficient, and fast drilling operations. However, due to the lack of effective lost circulation material (LCM), drilling time and drilling fluids are severely delayed and extra consumed, respectively. Herein, we innovatively propose and successfully develop a polymeric organic gelator using an emulsifier-free emulsion polymerization method and find that it achieves remarkable plugging ability in OBDF, superior to commercial LCMs, including asphalt, fine calcium carbonate, elastic graphite, and rubber particles. In detail, SMHDV with a branched C8 pendant group, benzene ring, isopropyl, and acetate groups is homogeneously dispersed in OBDF after hot rolling and capable of blocking permeable porous formations, resulting in a reduction of the cumulative filtration by 68 % at a concentration as low as 1 wt%. When added at a high concentration above 10 wt%, SMHDV turned into an organogel which can block cracks and prevent severe lost circulations together with other bridging materials. Furthermore, SMHDV maintains considerable plugging capacity in a wide temperature range of 80–150 °C, which meets most requirements of oil wells. The superior performance is attributed to the formation of supramolecular network structure in white oil due to the self-assembly behavior, which originated from the appropriate hierarchical polarities. In addition, the material can maintain stable rheological properties after hot rolling, improving the electrical stability of the drilling fluid. It is expected to form a set of scientific and efficient OBDF plugging technology to solve the leakage problems encountered during drilling.

Prediction of Collapsing Strength of High-Strength Collapse-Resistant Casing Based on Machine Learning

With the increasing complexity of shale gas extraction conditions, a large number of high-strength collapse-resistant casing is applied to the extraction of unconventional oil and gas resources. There are errors in the traditional API collapse strength formula. A high-precision and low-computational-cost model is needed for predicting the strength of high-collapsible casing. The key influencing factors of casing anti-collapse strength were determined as outer diameter, wall thickness, yield strength, ovality, wall thickness unevenness, and residual stress by analyzing the casing collapse mechanism. In response to the key factors mentioned above, a dataset was formed by measuring the geometric parameters of the full-size casing and collecting data on the results of the anti-collapse strength experiment, which was divided into a training set (70%) and a testing set (30%). Three machine-learning algorithms, a neural network, random forest, and support vector machine, were trained to predict the anti-extrusion strength. The correlation coefficient R2, root mean square error RMSE, and average relative MRE were used to evaluate the indexes for model preference evaluation. The results show that machine-learning algorithms have unique advantages in casing anti-collapsing strength prediction. Within which, the neural network prediction model has the best prediction effect, and its characteristics of high precision, low cost and high efficiency are more suitable for the prediction of casing extrusion strength. Its testing set R2 is 0.9733, RMSE is 0.0267 and MRE is 0.0782, and the prediction accuracy can reach 92.2% which is much higher than the API calculation result (63.3%). The network prediction model is suitable for casing anti-collapsing strength prediction and meets the actual prediction requirements.

Insights into in-situ imbibition behavior of fracturing fluid in propped shale fractures based on nuclear magnetic resonance: A case study from Longmaxi Formation shale, Sichuan Basin, China

Shale gas is an important component of unconventional oil and gas resources. Studying the imbibition behavior is helpful to optimize flowback parameters and enhance gas recovery. Recent imbibition studies have focused on shale matrix, and the pressure conditions discussed were mostly atmospheric. The initial imbibition behavior begins from propped fractures to matrix, but there are few studies working on explaining the imbibition behavior in propped fractures or the phenomenon of many shale wells exhibit higher productivity after a “soaking” period. Therefore, propped fracture samples were designed for imbibition and migration experiments. In order to accurately study the mechanism and main influencing factors of fracturing fluid imbibition and migration in propped and unpropped shale fractures under high temperature and high pressure, a series of experiments based on nuclear magnetic resonance (NMR) were carried out. Results showed that NMR T2 spectra of all samples exhibited a bimodal distribution. The final imbibition volume of fracturing fluid was positively related to pressure and fracture width. The imbibition effect of fracturing fluid was more evident in matrix pores under high pressure. In the migration during soaking stage, the fracturing fluid gradually migrated from large pores to small pores and gradually displaced the shale gas from the matrix, thus allowing the water blocking in propped fractures to self-unlock to some extent. Gas permeability decreased in the imbibition stage, while it recovered in the migration stage to some extent.

Paleoenvironmental characteristics and organic matter enrichment mechanisms of the upper Ordovician-lower Silurian organic-rich black shales in the Yangtze foreland basin, South China

The Wufeng Formation-Longmaxi Formation (O3w-S1l1) black shales within the Yangtze foreland basin (South China) hold significant potential as unconventional oil and gas resources. However, several challenges, including sluggish sedimentation rates, thin sedimentary layers, and notable homogeneity, hinder a comprehensive grasp of the organic matter enrichment (OME) mechanism within these shales. These challenges impede the exploration of unconventional oil and gas resources. This study aims to identify the O3w-S1l1 black shales in the Weiyuan area through a combined approach of organic and inorganic geochemical analyses. By doing so, it delves into the controlling mechanism behind OME in the black shales of the Yangtze foreland basin. The findings of this research reveal that the O3w-S1l1 black shales primarily consist of sapropelic kerogen and exhibit signs of over-maturation, with TOC content ranging from 0.43% to 8.21%. These shales are classified as organic-rich, mainly composed mixed and siliceous lithofacies. The presence of silica in the shales originates mainly from biogenic sources, and the highest TOC content coincides with a Sixs contribution of around 30% to the total silica content. During the late Katian, a global sea level drop led to an oxic paleoenvironment, transitioning into a euxinic paleoenvironment as sea levels rose in the early Rhuddanian. Notably, TOC content exhibited a significant correlation with paleoceanographic conditions (e.g., V/Cr, Ni/Co) and paleoproductivity levels (e.g., P/Al, Babio), while displaying a negative correlation with paleoclimate conditions (e.g., CIA, C-value), terrigenous detrital input intensity (e.g., Sixs, Ti/Al), and sedimentation rate ((La/Yb)N). Specifically, favourable conditions for OME encompass robust reducing seawater conditions, high paleoproductivity, a humid climate, reduced influx of terrigenous debris, and relatively elevated sedimentation rates. Regional tectonic movements (Guangxi movement) and fluctuations in relative sea levels exert influence over the deposition of O3w-S1l1 black shales. This study provides a valuable case study for exploring and developing shale gas resources within the Yangtze foreland basin.

Study on Brittleness Characteristics and Fracturing Crack Propagation Law of Deep Thin-Layer Tight Sandstone in Longdong, Changqing

Tight-sandstone oil and gas resources are the key areas of unconventional oil and gas resources exploration and development. Because tight-sandstone reservoirs usually have the characteristics of a low porosity and ultralow permeability, large-scale hydraulic fracturing is often required to form artificial fractures with a high conductivity to achieve efficient development. The brittleness of rock is the key mechanical factor for whether fracturing can form a complex fracture network. Previous scholars have carried out a lot of research on the brittleness characteristics of conglomerate and shale reservoirs, but there are few studies on the brittleness characteristics of sandstone with different types and different coring angles in tight-sandstone reservoirs and the fracture propagation law of sandstone with different brittleness characteristics. Based on this, this paper carried out a systematic triaxial compression and hydraulic fracturing experiment on the tight sandstone of Shan 1 and He 8 in the Longdong area of the Changqing oilfield. Combined with CT scanning cracks, the brittleness characteristics and fracturing crack propagation law of different types and different coring angles of sandstone under formation-confining pressure were clarified. The results show that there are great differences between different types of sandstone in the yield stage and the failure stage. The sandstone with a quartz content of 100% has the highest peak strength and a strong brittleness. Sandstones with a high content of natural fractures and dolomite have a lower peak strength and a weaker brittleness. There are also differences in the peak strength and fracture morphology of sandstone with different coring angles due to geological heterogeneity. The sandstone with a comprehensive brittleness index of 70.30 produces a more complex fracture network during triaxial compression and hydraulic fracturing than the sandstone with a comprehensive brittleness index of 14.15. The research results have important guiding significance for on-site fracturing construction of tight-sandstone reservoirs.

A feasibility study on time-lapse controlled-source electromagnetic method for hydraulic fracturing monitoring of Well Eyangye-2HF in Yichang, Hubei Province, China

Abstract Hydraulic fracturing plays a crucial role in enhancing reserves and production of unconventional oil and gas resources. Injecting fracturing fluids into the ground to improve reservoirs also introduces the risk of inducing earthquakes; thus, monitoring the migration of these fluids is crucial. The microseismic positioning method determines the fracturing fluid by locating microseismic events generated by the fractured rock strata; however, this method is susceptible to errors. Low-resistivity subsurface fluids can directly change electromagnetic field signals, making the electromagnetic method a technically advantageous approach for monitoring the migration of hydraulic fracturing fluids. The monitoring test data of Well Eyangye-2HF show that the time-lapse controlled-source electromagnetic (CSEM) method is suitable for hydraulic fracturing and has good monitoring effects. The results of CSEM method can also compensate for deficiencies in microseismic monitoring. The electric field (Ex) observed using the CSEM method can directly predict the distribution edge of the fracturing fluid, and the anomalous zone of the Exrate of change is consistent with the fracturing-fluid injection parameters and microseismic monitoring results. The analysis of field data and forward simulation, based on electrical logging results, led to the conclusion that hydraulic fracturing operations can cause changes in the resistivity of the target layer and surrounding strata. These changes are attributed to the synergistic effects of formation stress, temperature, and the fracturing fluid. The electric-field changes observed using the CSEM method may be caused by multiple factors; however, use of time-lapse CSEM for monitoring hydraulic fracturing is still feasible.

Effect of Matrix Permeability on a Horizontal Shale Gas Well Performance using a Fully Coupled Fluid Flow with Geomechanics Model

Recently, hydrocarbon production from unconventional oil and gas resources has emerged. The most common unconventional oil and gas resources are found in shale formations. These shale formations are well-known for being stress-sensitive. Usually, traditional tools are used to model and study production from such formations. However, conventional modeling techniques denote rock deformation using constant rock compressibility. Such an approach is useful for studying conventional hydrocarbon resources where formation stress sensitivity is insignificant. However, when it comes to modeling stress-sensitive formations such as shale formations, it is important to include the rock deformation and its effects on the overall fluid flow in porous media. To consider the rock deformation in the fluid flow model, the coupling of fluid flow with the geomechanics model has to be used. This study utilizes a fully coupled fluid flow with a geomechanics model. In addition, shale formations are also known to have an ultra-low matrix permeability, and production usually results from hydraulic fractures that act as flow conduits. Consequently, the effect of matrix permeability on hydrocarbon production is rarely studied. This study focuses on the effect of matrix permeability on the production performance of a single horizontal well in Barnett Shale. It also focuses on the effect of matrix permeability on production performance when the geomechanics effects are coupled with the fluid flow model and decoupled. The results show that the higher the matrix permeability, the better the production performance of the well. The results also show that the higher the matrix permeability, the higher the estimated cumulative production difference between the two models (when the geomechanics effects are coupled and decoupled).

The Exquisite Comparison of Shale Mineralogical-Geochemical Characteristics between Chang 7 Member and Chang 9 Member in Yanchang Formation, Ordos Basin

Significant amounts of unconventional oil and gas resources have been discovered in the Yanchang Formation of Ordos Basin. Shale layers deposited in Chang 7 member (divided into Chang 7-2 submember (C7-2SM) and Chang 7-3 submember (C7-3SM) and Chang 9 member (C9M)) are the main source rocks. Based on the comparison of mineralogical and geochemical characteristics, it is concluded that (1) in terms of mineralogical characteristics, the C7-3SM shale possesses the largest content of illite/smectite mixed layer and reducing minerals and the least quantity of quartz. The C9M shale shows the highest percentage of quartz and illite and the least amount of K-feldspar and Kaolinite. In C7-2SM and C9M shale, amorphous silica surrounded tightly by clay minerals is easily observed by the scanning electron microscopy. Besides the drilling orientation, the small content of quartz contributed to the lowest porosity for the C7-3SM shale. (2) In terms of geochemical characteristics, the C7-3SM shale exhibits high productivity due to type II1 kerogen. The organic matter in the C7-2SM and C9M shale contains mainly type II2 and possibly type III kerogen. The C9M shale exhibits the highest organic thermal maturity. The C7-3SM shale was formed in a relatively higher salinity of sedimentary water.

Numerical simulation of fracture propagation in deep coal seam reservoirs

AbstractAs an unconventional oil and gas resource, coalbed methane has become a key area of unconventional oil and gas exploration worldwide, and hydraulic fracturing is the critical technology for the efficient stimulation of coalbed methane. However, due to the strong heterogeneity of deep coal seam reservoirs and the development of natural cleat fractures, the fracture propagation path is quite complex and difficult to capture. In this study, we propose a hydraulic fracture propagation simulation method using the ABAQUS Software for natural cleat fracture networks and a fluid–solid fully coupled two‐dimensional finite element model with the global embedded cohesive zone model (CZM). CZM is established to simulate the propagation of hydraulic fractures in the heterogeneous combination of coal rock and mudstone. The accuracy of this model is verified by using Blanton's experiment criterion. Finally, the model is used to simulate the influence of cleat angle, cleat density, length ratio of coal rock and mudstone combination, and construction displacement on the propagation behavior of hydraulic fractures. This study aims to deepen the understanding of the mechanism of hydraulic fracture propagation in deep coal seams and provides guidance for deep coal seam fracturing and hydraulic fracturing design.

Numerical simulation of proppant transport from a horizontal well into a perforation using computational fluid dynamics

With the increasing global demand for oil and gas, the development of unconventional resources such as shale gas is becoming ever more important. The key to developing unconventional oil and gas resources lies in horizontal wells with multistage fracturing technology. In the process of horizontal well segmentation fracturing, the distribution of the proppant among multiple clusters has a significant influence on the fracturing effect. However, the influence of various factors on the entry of proppant into the perforation and then into the fracture along the wellbore is unclear. In this paper, based on the flow characteristics of proppants in fracturing fluids, we investigate the wellbore–perforation proppant transport using a Eulerian multiphase flow model. The effect of different factors on proppant entry into the perforation in horizontal wells is studied. We first verify that the computational fluid dynamics model satisfies the accuracy requirements for studying the sand-carrying efficiency of proppants in a perforation cluster. Second, the effects of the proppant size, proppant density, fracturing fluid viscosity, perforation diameter, and fracturing fluid flow rate on the proppant transport efficiency are investigated. Finally, a mathematical model of the sand-carrying efficiency is established by multivariate nonlinear fitting. The results show that the proppant size has a more significant effect on proppant settling at low wellbore flow rates. Increasing the diameter of the proppant particles can accelerate proppant settling. Higher wellbore flow rates tend to reduce the sand-carrying efficiency, although using a low-density proppant can mitigate the effect of the wellbore flow rate. At low wellbore flow rates, increasing the perforation size makes it easier for the proppant to enter bottom perforations. Increasing the fluid viscosity helps to distribute the proppant evenly between perforations in different directions, but this effect diminishes as the flow rate increases. Finally, a formula for the wellbore sand-carrying efficiency is obtained and validated, providing a basis for optimizing the distribution of the proppant in the perforation. The results from this paper enhance our understanding of the sand and fluid feeding patterns of each perforation cluster and provide direction for improving the construction process and enhancing the fracture inflow capacity.

A Method for Judging the Effectiveness of Complex Tight Gas Reservoirs Based on Geophysical Logging Data and Using the L Block of the Ordos Basin as a Case Study

As an important unconventional oil and gas resource, the tight gas reservoir faces many technical challenges due to its low porosity, low permeability, and strong heterogeneity. Among them, the accurate definition of effective reservoirs and ineffective reservoirs in tight gas reservoirs directly affects the formulation and adjustment of subsequent development plans. This paper proposes a reservoir effectiveness identification method based on double factors based on conventional geophysical logging data and core experimental data. The double factors considered are based on the logging response and physical parameters of the reservoir. The identification factor F1 is obtained by using the difference in the logging response values of the natural gamma logging curve, compensated density logging curve, and acoustic time difference logging curve in different reservoirs combined with mathematical operation, and the identification factor F2 is calculated by using porosity parameters combined with Archie’s formula. The validity of the reservoir can be judged by the intersection of the above double factors. This method is applied to the Shihezi Formation in the L block, and the applicability of the double factors is compared and analyzed using the traditional method. The results show that the method has strong applicability in tight gas reservoirs and that the accuracy rate reaches 96%. Compared with the direct use of the porosity lower limit method, the accuracy of the judgment is significantly improved, and the calculation is simple, easy to implement, and unaffected by mud invasion. For study areas with different geological backgrounds, the process of this method can also be used to determine the effectiveness of the reservoir. The reservoir effectiveness identification method proposed in this paper has practical engineering significance and lays a solid foundation for subsequent fluid property identification, production calculation, and development plan formulation and adjustment.