Minimum Horizontal Stress Research Articles

The Casing Collapse Mechanism in Salt Formations in Deepwater Fields in Brazil

Salt formations are commonly encountered during oil and gas drilling. Due to the rheological properties of salt rocks, casing collapse accidents happen frequently. Under action of nonuniform geostress, casing failure has become an important influencing factor that restricts the exploration and development benefits of deep and ultra-deep wells. Casing stress in a period after well cementation in the salt formation of Brazilian deepwater fields was analyzed. Results show that the nonuniform geostress is instantaneously applied on the cement sheath when well cementation is completed in the salt formation and then transferred to the casing. Stress on the inner wall grows with an increase in the angle with the direction of the maximum horizontal principal stress and it reaches the maximum in the direction of the minimum horizontal principal stress. As the creep continues, stress on the inner wall of casings gradually enlarges and the circumferential stress in inner rings tends to be uniform, which means that creep of the formation weakens the nonuniformity of casing deformation. The collapse pressure on the outer wall of casings tends to increase at first and then decrease as the angle with the direction of maximum horizontal principal stress enlarges. Stress on the inner wall of casings in the salt formation reduces with the increasing thickness of casings selected, and the casing strength is improved as the wall thickness increases. The research results provide certain theoretical guidance for the strength check of casings in well cementation engineering in salt formations.

Propagation pattern of cracks around a shale borehole via the cohesive element method

Shale gas is a cutting edge energy source for development, and reserves are abundant. However, shale microcracks develop and tend to form macroscopic fractures during drilling, which can cause severe wellbore instability. Therefore, in combination with rock mechanics theory and fracture mechanics theory, the cohesive element method is adopted to establish a numerical model for differential crack propagation due to bottomhole pressure on the basis of the B-K fracture criterion. The propagation pattern of cracks around a wellbore is simulated, and the influences of rock mechanical parameters, the initial crack length, the direction of crack distribution, and minimum horizontal stress on crack propagation are analyzed. The research results indicate that the larger the Young’s modulus of shale is, the easier it is for cracks to propagate. The Poisson’s ratio of shale has a large influence on crack widening, but its effect on the crack length is weak. The larger the angle between the crack and the maximum horizontal stress is, the more difficult it is for the crack to propagate. The greater the minimum horizontal stress is, the more difficult it is for cracks to propagate. The initial crack length has a weak effect on crack propagation.

Study on Distribution Law of Ground Stress in Main Coal Seam of Qinshui Coalfield

Abstract In order to investigate the distribution patterns of in situ stress in the main coal seams (3# and 15#) of the Qinshui coalfield, an in-depth analysis was conducted on the in situ stress measurement results obtained from 139 measurement points across 46 mines within the mining area. The findings indicate that the maximum horizontal principal stress in the coal mining area of both seams is generally higher than the vertical principal stress. The stress field exhibits characteristics of a tectonic stress field, while deeper regions display features of a vertical stress field. The in situ stress values in the mining area of coal seam 3# are predominantly characterized by moderate stress field zones, while those in the mining area of coal seam 15# are mainly composed of low to moderate stress field zones. The maximum horizontal principal stress in the Yangquan and Changzhi mining areas for both coal Seams 3# and 15# is concentrated in the NE direction, whereas in the Jincheng mining area, it is predominantly concentrated in the NW direction, indicating a clear directionality. With increasing depth, the following trends can be observed approximately: the maximum and minimum horizontal principal stress values generally exhibit an increasing trend, and the geological structures throughout the mining area are primarily dominated by horizontal tectonic movements; the lateral pressure ratio gradually decreases and tends to concentrate near the value of 1; the relative difference between the maximum and minimum principal stresses tends to increase, with the horizontal principal stress difference ratio concentrating near 0.5. The relationship between the average horizontal principal stress ratio (k) and vertical principal stress at different depths within the measured area follows Hawke-Brown’s general law for this relationship curve. The research results have important guiding significance for the design of coal mining engineering in this area.

Moment tensors for small earthquakes and the stress regime in the mid-Atlantic United States

Focal mechanisms for small magnitude earthquakes (M ~ 1.3–4.1) in the mid-Atlantic region of the United States have been determined using a double-couple moment tensor inversion procedure. The 26 new focal mechanisms obtained, when combined with previously published mechanisms, show a pattern of reverse faulting in the easternmost portion of the study area and strike-slip faulting in the west, consistent with previous studies. The change in focal mechanisms from east to west helps to constrain the geographic location of the east-west transition in the stress regime to a NE-SW area within central Pennsylvania within proximity of the Allegheny Front. Stress inversions performed to constrain variations in the stress state across the region show that the maximum compressive stress varies only slightly, but that the near-vertical stress is the minimum compressive stress in the east and transitions to the intermediate compressive stress in the west, as expected for an east-west transition in reverse to strike-slip faulting. Analysis of driving forces causing the stress change suggests that tectonic terrane structure, glacial isostatic adjustment, and changes in gravitational potential energy have little effect on the stress field in this region, leaving the interaction of sublithospheric mantle flow with the eastern edge of the Laurentian cratonic lithosphere beneath central Pennsylvania as a primary explanation. The cratonic lithospheric keel may cause a deflection in mantle flow, thereby changing the stress field enough so that the magnitude of the vertical stress in relation to the minimum horizontal stress results in strike-slip as opposed to reverse faulting.

Mechanical earth model coupled with critical drawdown pressure to mitigate sand production in the Nahr Umr Formation, Southern Iraq

Sand production is one of the major challenges in the oil and gas industry. This problem exists when sand is produced along with oil and gas causing relevant damage to production equipment, thus decreasing in the productivity of wells. Therefore, a comprehensive geomechanical analysis is necessary to mitigate sand production. This study aims to assess the potential of sand production across the Nahr Umr Formation using the 1-D Mechanical Earth Model (MEM). Tech-log software coupled with well log and core data have been employed to accurately determine the possible rock geomechanical parameters, in-situ stresses and pore pressure at which rock failure might occur. Once MEM is complete, the Poro-elastic method is used to figure out the critical drawdown pressure (CDDP) and accurately predict the sand production onset. Additionally, the effect of different well completion types on the value of the CDDP was examined, and thus it was concluded that cased hole completion is the first line of defense against sand production, and can also be considered as a strategy of sand control because it reduces the sand production potential and increases the operation drawdown. Furthermore, to demonstrate the effectiveness and applicability of our method and technique, a case study was conducted to illustrate the reliability of our method in predicting sand-producing intervals under different depletion rates and completion scenarios. The finding showed that the depth 2527.7 m is a potential location for sand production as the CDDP reads a positive value revealing a high potential for rock failure. Moreover, sensitivity analysis has been performed by considering different ranges of Unconfined Compressive Strength (USC), Poisson ratio, minimum horizontal stress (Shmin), maximum horizontal stress (SHmax), vertical stress, sand grain size, perforation diameter, perforation orientations, stress ratio, and hole deviation. These factors play an essential role in optimal decisions related to real-time sand control techniques. Through the results, it is clear that as the UCS, Shmin, and SHmax increase, the sand-free drawdown and depletion also increase, and vice versa. Also, results show that as the depletion rate increases, the CDDP decreases in both cased and open hole conditions, revealing that the onset sanding likely occurs as the depletion rate is elevated. Based on these findings, a necessary modification to the completion design has been made, ensuring sand-free production from a clastic reservoir located in the southern area of Iraq.

Fracture Propagation Laws and Influencing Factors in Coal Reservoirs of the Baode Block, Ordos Basin

The expansion of hydraulic fractures in coalbed methane (CBM) reservoirs is key to effective stimulation, making it essential to understand fracture propagation and its influencing factors for efficient resource development. Using petrological characteristics, logging data, microseismic monitoring, and fracturing reports from the Baode Block on the eastern Ordos Basin, this study systematically investigates the geological and engineering factors influencing hydraulic fracture propagation. The real-time monitoring of fracture propagation in 12 fractured wells was conducted using microseismic monitoring techniques. The results indicated that the fracture orientations in the study area ranged from NE30° to NE60°, with fracture lengths varying between 136 and 226 m and fracture heights ranging from 8.5 to 25.3 m. Additionally, the fracturing curves in the study area can be classified into four types: stable, descending, fluctuating, and falling. Among these, the stable and descending types exhibit the most effective fracture propagation and are more likely to generate longer fractures. In undeformed–cataclastic coals and bright and semi-bright coals, long fractures are likely to form. When the Geological Strength Index (GSI) of the coal rock ranges between 60 and 70, fracture lengths generally exceed 200 m. When the coal macrolithotype index (Sm) is below 2, fracture lengths typically exceed 200 m. When the difference between the maximum and minimum horizontal principal stresses exceeds 5 MPa, fractures with length >180 m are formed, while fracture heights generally remain below 15 m. From an engineering perspective, for the study area, hydraulic fracturing measures with a preflush ratio of 20–30%, an average sand ratio of 13–15%, and a construction pressure between 15 MPa and 25 MPa are most favorable for coalbed methane production.

Identification of Fracture Extension Modes During Hydraulic Fracturing in Coalbed Methane Vertical Wells: A Case Study From the Southern Shizhuang Area of the Qinshui Basin, China

ABSTRACTThe accurate identification of fracture extension patterns in hydraulic fracturing can provide important guidance for the optimisation of fracturing parameters. In this paper, factors such as effective hole friction and wellbore flow friction during fracturing are fully considered, and a calculation model of net bottom‐hole pressure of fracturing is constructed. By introducing the change rate of net bottom‐hole pressure and the changing characteristics of the fracturing curve, seven fracture extension modes during hydraulic fracturing in coalbed methane vertical wells are established. The accuracy of the identification method is verified by the fracture monitoring and production results in Shizhuang South Block. The results show that fracture elongation is mainly controlled by in situ stress difference, angle between natural fracture and maximum principal stress, coal tensile strength, fracturing time, proppant and angle between other factors. When the fracture construction parameters are fixed, the smaller the difference between maximum and minimum horizontal principal stresses and the smaller the natural fractures and maximum horizontal principal stresses. When the reservoir potential is similar, the effective extension index is positively correlated with the gas production effect, and the effective extension index can effectively judge the fracturing effect. The higher the proportion of effective extension mode, the longer the extension time and the higher the stable daily gas production. The research results provide a method and reference for clearly identifying the fracture extension and the occurrence conditions of different extension modes in the hydraulic fracturing process.

Developing a geomechanical model to predict breakdown pressure in a vertical borehole using failure analysis: a case study

Breakdown is an important process in geomechanics; a very complex process in hydraulic fracturing which has been the subject of extensive research in the literature. There exist several models in the literature for predicting the breakdown pressure. In this research, the breakdown pressure for hydraulic fracturing in a vertical borehole was modeled using 2D and 3D failure analysis. In the geomechanical model constructed in this case study, elastic moduli were obtained using petrophysical data as well as data extracted from core analysis. The in-situ stress state of the reservoir was obtained by poroelastic horizontal strain model and was then validated by field data. To test the accuracy of the horizontal strain model, several models were used to obtain the minimum horizontals stress. At the end, the induced principal stresses inside the borehole were modeled by Kirch Equations. Four failure criteria, namely Mohr–Coulomb, 2D Hoek–Brown, Hubbert-Willis and 3D Mogi-Coulomb were used to obtain the breakdown pressure for the target reservoir. Based on the prediction results of these failure criteria, it was obtained that 2D Hoek–Brown, Hubbert-Willis, and 3D Mogi-Coulomb criteria resulted in seemingly unrealistic breakdown pressures with respect to the minimum horizontal stress gradient. The Mohr–Coulomb criterion produced lower breakdown pressure gradients, yet closer to the minimum horizontal stress values, even though it neglects the effect of intermediate stress.

Multi-Task Learning Network-Based Prediction of Hydraulic Fracturing Effects in Horizontal Wells Within the Ordos Yanchang Formation Tight Reservoir

Accurate prediction of fracture volume and morphology in horizontal wells is essential for optimizing reservoir development. Traditional methods struggle to capture the intricate relationships between fracturing effects, geological variables, and operational factors, leading to reduced prediction accuracy. To address these limitations, this paper introduces a multi-task prediction model designed to forecast fracturing outcomes. The model is based on a comprehensive dataset derived from fracturing simulations within the Long 4 + 5 and Long 6 reservoirs, incorporating both operational and geological factors. Pearson correlation analysis was conducted to assess the relationships between these factors, ranking them according to their influence on fracturing performance. The results reveal that operational variables predominantly affect Stimulated Reservoir Volume (SRV), while geological variables exert a stronger influence on fracture morphology. Key operational parameters impacting fracturing performance include fracturing fluid volume, total fluid volume, pre-fluid volume, construction displacement, fracturing fluid viscosity, and sand ratio. Geological factors affecting fracture morphology include vertical stress, minimum horizontal principal stress, maximum horizontal principal stress, and layer thickness. A multi-task prediction model was developed using random forest (RF) and particle swarm optimization (PSO) methodologies. The model independently predicts SRV and fracture morphology, achieving an R2 value of 0.981 for fracture volume predictions, with an average error reduced to 1.644%. Additionally, the model’s fracture morphology classification accuracy reaches 93.36%, outperforming alternative models and demonstrating strong predictive capabilities. This model offers a valuable tool for improving the precision of fracturing effect predictions, making it a critical asset for reservoir development optimization.

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°.

Spatially varying stress regime in the southern Junggar Basin, NW China

The southern Junggar Basin in NW China is an important tectonic unit in the region of the Tibetan Plateau and has been the focus of considerable research into its tectonic processes and geodynamic setting. However, the relationship between deep structural deformation and stress in this region remains unclear. This study investigates the Gaoquan and Hutubi anticlines in the southern Junggar Basin using three-dimensional geophysical data and a finite-element numerical simulation to examine the crustal stress distribution and stress regime at depths of up to 7 km. Numerical simulation results indicate that the stress regime in the southern Junggar Basin changes from west to east. In the western part of the region, including the Gaoquan anticline at depths of 4900–6100 m, the maximum horizontal principal stress shows a peak of 140–200 MPa, the minimum horizontal principal stress is 110–170 MPa, and the vertical principal stress is 115–175 MPa, indicating a mixed stress regime incorporating both compression and strike-slip components. In the eastern part of the region, including the Hutubi anticline at depths of 5400–7800 m, the maximum horizontal principal stress shows a peak of 160–280 MPa, the minimum horizontal principal stress is 155–250 MPa, and the vertical principal stress is 125–215 MPa, indicating a compressive stress regime. The stress magnitude and orientation are affected by the presence of faults and depth in the crust. Combining these results with the regional tectonic setting, it is considered that the geometrical relationship between pre-existing faults and the current stress field is the main control on the west–east differentiation in the stress regime, with spatial variations in the mechanical parameters of the crust and the pressure coefficient being secondary factors. These results provide insights into the relationship between stress and deformation, and support the updated version of the World Stress Map database.

Surrogate Model of Shale Stress Based on Plackett-Burman and Central Composite Design

Summary Multifactor analysis and accurate prediction of dynamic stress in shale reservoirs are of great practical significance for designing hydraulic fracturing. In this paper, a surrogate model for the rapid prediction of shale stress is proposed by considering the geomechanical heterogeneity and multiscale seepage mechanism of shale gas. The Plackett-Burman method is used to compare the influence of different parameters on shale stress, and significant parameters are selected as decision variables for establishing a surrogate model. The surrogate model for predicting stress is obtained by central composite design fitting, and the interaction of significant factors on shale stress is studied. The results show that after considering the heterogeneity, the minimum horizontal stress fluctuation range is 20.25 to 44.03 MPa and the maximum horizontal stress fluctuation range is 26.46 to 49.77 MPa in the area controlling hydraulic fracture. The initial reservoir pressure, as well as the length and width of hydraulic fractures, are the key factors influencing reservoir stress. The analysis of variance demonstrates that the proposed method is effective for predicting shale stress. The research results are helpful for gaining a deeper understanding of the evolution mechanism of dynamic stress fields in shale reservoirs and provide guidance for treatment design and dynamic optimization of gas wells.

Stability Characteristics of Natural Gas Hydrate Wellbores Based on Thermo-Hydro-Mech Modeling

During drilling operations, drilling fluids undergo heat exchange with hydrate-bearing formations. The intrusion of drilling fluids affects hydrate stability, leading to variations in stress fields around a wellbore and complex scenarios such as borehole collapse, significantly hindering the efficient development of natural gas hydrate resources. This study establishes a thermo-hydro-mech model for hydrate-bearing inclined wells based on linear thermoelastic porous media theory and an appropriately high inhibitive drilling fluid temperature. This research reveals that drilling should follow directions of minimum horizontal stress or perpendicular to maximum horizontal stress during drilling operations to control wellbore stability. Hydrate decomposition due to factors like drilling fluid pressure and temperature can rapidly reduce the strength of low-saturation formations, significantly increasing the risk of wellbore instability. Therefore, selecting appropriate highly inhibitive and low-temperature drilling fluids during drilling operations helps control hydrate decomposition and reduce fluid intrusion, thereby mitigating risks associated with wellbore instability.

Automated Borehole Image Interpretation Using Computer Vision and Deep Learning

Summary Reservoir characterization is critical for successful oil and gas exploration, heavily reliant on detailed formation analysis from formation microimager (FMI) logs. However, interpreting these complex logs is time-consuming, subjective, and requires expert-level knowledge. This study addresses this challenge by proposing a novel approach that integrates computer vision (CV) and deep learning (DL) for automated and real-time interpretation of FMI logs. Our methodology leverages CV and DL techniques for automated feature extraction and classification from FMI data. A comprehensive training data set encompassing more than 2,500 images is utilized to train the DL model, enabling the identification of more than 50 distinct geological features, including bedding planes, fractures, and mineral variations. In addition, the study explores the creation of local stress maps from drilling-induced fractures to determine the present-day maximum horizontal stress (SHmax) orientation, crucial for optimizing wellbore stability and hydraulic fracturing strategies. This research presents a groundbreaking advancement in reservoir characterization through the synergy of automated FMI interpretation, CV, and DL. The developed model exhibits exceptional accuracy in geological feature classification, significantly surpassing traditional, human-centric interpretations. For instance, the model achieves a remarkable 92% accuracy in classifying ore than 50 geological features, demonstrably outperforming conventional methods. Furthermore, the developed model was applied to actual field cases to predict the stress field. The model was able to accurately predict the minimum horizontal stress (Shmin) and SHmax based on FMI logs, and the results were used to refine the geomechanical modeling and optimize hydraulic fracture orientation for enhanced hydrocarbon recovery. This work establishes a new benchmark for applying artificial intelligence in subsurface analysis, paving the way for future advancements in reservoir management and geomechanics. The implications are far-reaching, offering greater precision in geological interpretations, improved decision-making for production strategies, and ultimately, a more sustainable approach to hydrocarbon extraction. By automating tedious and subjective tasks, this approach not only reduces reliance on experts but also frees up valuable time for more strategic tasks. The ability to extract critical geological information with such accuracy from complex FMI logs translates to significant improvements in reservoir characterization and production efficiency.

The fracture propagation law of axially symmetric intersecting precut hydraulic fracturing in mine rock-breaking

As a mine rock-breaking technique, hydraulic fracturing technology can reduce the amount of explosives used, which enhance safety and reduce environmental pollution in mines. After precutting along the borehole axis, hydraulic fractures will expand along the precutting direction within a certain range and reduce initiation pressure. These hydraulic fractures cut through the rock mass, reducing its integrity and weakening its mechanical properties. Hydraulic fracturing with axially symmetric intersecting precut fractures not only controls the multi-directional propagation of fractures but also increases the fractures within rock mass. The lattice method simulated the hydraulic fracturing process, focusing on the parameters like angles between precut fractures and the minimum horizontal principal stress, the maximum horizontal principal stress, and angles between intersecting precut fractures. Results indicate that the hydraulic fractures propagate along intersecting precut fractures, forming main and interconnected secondary fractures. The directional cutting effect is influenced by the number of secondary fractures. With the increase in the angle between precut fractures and the minimum horizontal principal stress, the maximum horizontal principal stress, the angle between precut fractures, the area of secondary fractures decreased, and the expansion extent of main fractures along the precut fractures increased, indicating better directional effects. The study identifies relationships between initiation time, initiation pressure, and parameters. These findings provide valuable technical guidance for designing on-site construction plans for hydraulic fracturing projects involving intersecting precut fractures.

Prediction of Sand Production from Poorly Consolidated Formations Using Artificial Neural Network: A Case Study, Nahr Umr Formation in Subba Oil Field

Sand production in poorly consolidated formations is a significant challenge to the oil and gas industry, resulting in reduced production and compromised equipment integrity. The oil and gas industry has recently become interested in data analytics because it has significantly simplified, accelerated, and reduced the cost of data visualization. The intriguing new approaches in artificial intelligence development promise to offer long-term solutions to the increasing problems affecting the petroleum industry's operations. Any completion operation in sandstone formations is based on determining whether or not a well will produce sand. It is economically unfavorable to the Nahr Umr Formation to install sand control equipment for wells that don't produce sand. This study aims to create an efficient and precise artificial neural network that can predict sanding in sandstone formations. To achieve this, we developed a two-layered ANN with a back-propagation algorithm using JMP software. The model formulation included various geological and mechanical factors that could impact sand detachment, such as Young’s modulus (YME), Poisson’s ratio, minimum and maximum horizontal stresses (SHMIN and SHMAX), pore pressure, shale volume, and formation strength. The study acquired data from both local fields, specifically the Amarah oilfield, and non-local fields from the literature. Two sets were created from the data: a training set comprising 75% of the data, and a test set comprising 25% of the data, both of which were classified. The speed and accuracy of a learning process in an Artificial Neural Network depends on the size of the data set, the number of hidden layers, and the input parameters. The statistical measures such as accuracy, confusion matrix, root mean square error, and generalized RSquare demonstrate the strong efficacy of the created Artificial Neural Network model. The results indicate a significant likelihood of sand production occurring over the perforation intervals across Su-4 and Su-5 wells. The method's unique feature is its ability to isolate shale areas and identify weak areas capable of producing sand in sandstone formations. In conclusion, it is determined that an Artificial Neural Network employing the back-propagation algorithm is a simple, reliable, and easy-to-use method for accurately predicting sand production.

Three-Dimensional Coupled Temporal Geomechanical Model for Fault-Reactivation and Surface-Deformation Evaluation during Reservoir Depletion and CO2 Sequestration, Securing Long-Term Reservoir Sustainability

Assessing reservoir subsidence due to depletion involves understanding the geological and geophysical processes that lead to ground subsidence as a result of reservoir fluid extraction. Subsidence is a gradual sinking or settling of the Earth’s surface, and it can occur when hydrocarbons are extracted from underground reservoirs. In this study, a time-integrated 3D coupled geomechanical modeling incorporating the fourth dimension—time—into traditional 3D geomechanical models has been constructed utilizing seismic inversion volumes and a one-dimensional mechanical Earth model (1D MEM). The 3D geomechanical model was calibrated to the 1D MEM results. Geomechanical rock properties were derived from the density and sonic log data that was distributed with conditioning to the seismic inversion volumes obtained from running pre-stack inversion. The standard elastic parameter equations were used to generate estimates of the elastic moduli. These properties are dynamic but have been converted to static values using additional equations used in the 1D MEM study. This included estimating the Unconfined Compressive Strength. In situ stresses were matched using different minimum horizontal principal stress gradients and horizontal principal stress ratios. The match is good except where the weak carbonate faults are close to the wells, where the Shmin magnitudes tend to decrease. The SHmax orientations were assessed from image log data and indicated to be 110° in the reservoir section. A time-integrated 3D coupled simulation was created using the finite-element method (FEM). The effective stresses increase while there is depletion in all directions, especially in the Z direction. The predicted compaction in the reservoir and overburden was 350 mm. Most of the compaction occurs at the reservoir level and dissipates towards the surface (seabed). Furthermore, the case displayed no shear failure that might cause or fault reactivation in the reservoir interval (Kangan–Dalan Formations) located in the simulated area. In this study, we applied an integrated and comprehensive geomechanical approach to evaluate subsidence, fault reactivation and stress alteration, while reservoir depletion was assessed using seismic inversion, well logs, and experiment data. The deformation monitoring of geological reservoirs, whether for gas storage or hazardous gas disposal, is essential due to the economic value of the stored assets and the hazardous nature of the disposed materials. This monitoring is vital for ensuring the sustainability of the reservoir by maintaining operational success and detecting integrity issues.

The Gas Production Characteristics of No. 3 Coal Seam Coalbed Methane Well in the Zhengbei Block and the Optimization of Favorable Development Areas

The characteristics and influencing factors of gas production in CBM wells are analyzed based on the field geological data and the productivity data of coalbed methane (CBM) wells in the Zhengbei block, and then the favorable areas are divided. The results show that the average gas production of No. 3 coal seam CBM wells in the study area is in the range of 0~1793 m3/d, with an average of 250.97 m3/d; 80% of the wells are less than 500 m3/d, and there are fewer wells above 1000 m3/d. The average gas production is positively correlated with gas content, critical desorption pressure, permeability, Young’s modulus, and Schlumberger ratio, and negatively correlated with fracture index, fault fractal dimension, Poisson’s ratio, and horizontal stress difference coefficient. The relationship between coal seam thickness and the minimum horizontal principal stress is not strong. The low-yield wells have the characteristics of multiple pump-stopping disturbances, unstable casing pressure control, overly rapid pressure reduction in the single-phase flow stage, sand and pulverized coal production, and high-yield water in the later stage during the drainage process. It may be caused by the small difference in compressive strength between the roof and floor and the coal seam, and the small difference in the Young’s modulus of the floor. The difference between the two high-yield wells is large, and the fracturing cracks are easily controlled in the coal seam and extend along the level. The production control factors from strong to weak are as follows: critical desorption pressure, permeability, Schlumberger ratio, fault fractal dimension, Young’s modulus, horizontal stress difference coefficient, minimum horizontal principal stress, gas content, Poisson’s ratio, fracture index, coal seam thickness. The type I development unit (development of favorable areas) of the Zhengbei block is interspersed with the north and south of the block on the plane, and the III development unit is mainly located in the east of the block and near the Z-56 well. The comprehensive index has a significant positive correlation with the gas production, and the prediction results are accurate.

Evaluation of the Lower Cretaceous Alam El Bueib Sandstone reservoirs in Shushan Basin, Egypt – Implications for tight hydrocarbon reservoir potential

This study presents the evaluation of the potential reservoir intervals in the early Cretaceous Alam El Bueib Formation of the Shushan Basin, Western Desert. Seismic 2D lines, and wireline logs (including image logs) were assessed to characterize the potential intervals. The study area is characterized by E-W to ENE-WSW striking parallel sets of steeply dipping normal faults. Based on the breakouts on image log, the regional maximum horizontal stress orientation is inferred as NE-SW. The AEB Formation, as observed on the image log, consists of massive sandstones, planar laminated siltstones, sandstone-siltstone heteroliths and laminated shales, deposited in a fluvial depositional environment. The bedding planes are WNW-ESE striking with a mean true dip of NNE (around 10°). Wireline log based quantitative petrophysical assessment identified multiple promising hydrocarbon-bearing reservoir intervals within the AEB Formation. The potential reservoir intervals are clean with shale content <10% with water saturation <50%. However, all these intervals are tight with effective porosity between 4 and 12%, dominantly ∼5%. Such tight effective porosity can be contributed by extensive silica cementation in the AEB Formation, as seen from the nearby fields in Western Desert. High porosity zones are observed to be water-bearing. The wells drilled in the north and northeastern area exhibit a cumulative net pay thickness between 70 and 150 ft, while south-southeastern region exhibits a very low cumulative net pay of 10–30 ft. Based on the breakout son image log, the regional minimum horizontal stress orientation is inferred as NW-SE, which can be preferred azimuth for placing highly deviated or horizontal wells to exploit such tight clastic reservoirs by optimizing hydraulic fracture propagation. The formation evaluation presented in this work shed critical insights into the tight hydrocarbon reservoir potential of the early Cretaceous AEB.

Pore pressure-minimum horizontal stress coupling estimation in Tunu Field, Lower Kutai Basin, Indonesia

Quantifying the change of minimum horizontal stress (Shmin) in response to pore pressure is vital, particularly at the development stage of a hydrocarbon field. However, estimates of the coupling ratio between these parameters, either at basin or reservoir scales, are not well defined in Indonesia’s sedimentary basin, such as Lower Kutai Basin. This study investigates the coupling ratio between Shmin and pore pressure in one of the gas fields within the basin, Tunu Field, using available evidence from an extensive data set of direct pressure measurement, leak-off test, extended LOT, Mini-Frac, and lost circulation. Previous studies have reported overpressured and depleted reservoirs. Nevertheless, the evolution of Shmin due to the change in pore pressure has yet to be well established. This study reveals a Shmin and vertical stress ratio of 0.87 which may relate to the stiffening of the shales via clay diagenesis/cementation. Coupling ratios between Shmin and pore pressure are 0.3 for the overpressured zone at the basin scale and 0.42 for the depletion at the reservoir scale. The approach used has been shown to produce similar coupling ratio (or stress path) results to other basins globally, thus providing a useful estimate of the Shmin and pore pressure relationship for the Tunu Field, and potentially other fields in the Lower Kutai Basin. For the application to infill drillings within the field, this study indicates Shmin decreases in response to pore pressure depletion due to production, ranging from 1.7 to 2.3 ppg within the hydrostatic zone and from 2.5 to 3.7 within the overpressured zone, equivalent to a Pore Pressure (PP)-Shmin window decrease of approximately 28% to 37% and approximately 40% to 88%, respectively. In addition, strike-slip faulting is suggested as the likely in situ stress regime in the Tunu Field.