Hydraulic Fracture Stimulation Research Articles

Hydraulic Fracturing Characteristics and Stimulation Optimization of Tuffaceous Sandstone Reservoir in San Jorge Basin, Argentina

According to the post fracturing production performance characteristics of the operation wells in Sinopec Argentina work area of San Jorge basin, the more intensive the reconstruction is, the worse the effect is. By comparing the characteristics of typical wells, combining with the distribution characteristics of reservoir, the influence of tuffaceous matter, the state of in-situ stress, and the propagation law of hydraulic fractures, the main factors causing the abnormal performance are revealed. The characteristic parameters of typical wells in the work area are compared, and the main control factors affecting the key parameters of production are discussed. From the fracture scale, working fluid system, pumping parameters and other aspects, the targeted measures are optimized. The practice shows that the success rate of low intensity transformation is higher, which is nearly 10% higher than that of medium intensity transformation; within one year after fracturing, the average daily oil production of single well is 3.0 m³ higher, and the efficiency is remarkable. According to the characteristics of the work area, the small-scale and low-intensity sand adding transformation scheme is adopted, which improves the success rate and efficiency of hydraulic fracturing operation, and provides a new technical idea for tapping the potential of the next process.

GEOLOGICAL CHALLENGES IN HYDRAULIC FRACTURING OPERATION: A CASE STUDY IN UNDISCLOSED PETROLEUM FIELD IN OMAN

Production of hydrocarbons is hampered by obstacles known as formation damage. This damage needs to be removed or bypassed to retain well productivity. Hydraulic fracturing stimulation is one of the techniques used to overcome formation damage and enhance the productivity of the formation by maximizing the ultimate recovery. It was highlighted that there are some challenges associated with this technique and the most difficult challenges in hydraulic fracturing design and implementation are those related to geology of the reservoir. This study was, therefore, aimed at addressing the main geological challenges and providing the best low-cost solution and practice that leads to easy and successful stimulation operation. As an engineering solution in this study, fracturing geometry design was addressed to overcome geological challenges using advance simulator tool. Multiple fracking design by using computer simulation for a set of geological parameters aid on predicting the result out and avoid any complication in future production. Other challenges addressed by intelligent numerical evaluation used as a best practice in well stimulation to maximize the benefits of well production recovery. Optimizing fracturing fluid is also an important element covered in this study. An investigation was conducted on formation permeability variation for heterogeneous rock formation as one of the geological challenges faced by hydraulic fracturing operation for further understanding the geometry of fracturing for the success of stimulation operation. By fixing all other formation and pumping variables it was observed that formation permeability influences the length of fracture geometry, which could lead to stimulate out of pay zone.Keywords: hydraulic fracturing, geology, fracking, treatment fluid, geological challenges, frac treatment

RETRACTED: The increased viscosity effect for fracturing fluid imbibition in shale formation

Abstract Understanding water imbibition behaviors in shale formations plays an essential role in shale gas development and risk assessment on shallow aquifer contamination, as imbibition is the main mechanism for fracturing fluid uptake during a hydraulic fracturing stimulation process. The effective viscosity of water in shale formations is usually different from that of the bulk phase due to confined conditions. In this work, a model considering interactions between water and a solid surface is proposed to predict the effective viscosity of water at the nanoscale. This model is derived based on a classical molecular kinetic theory and incorporates the disjoining pressure. Published experimental data is used to validate the model. It is demonstrated that the effective viscosity of water highly confined in hydrophilic nanopores is much higher than that of the bulk phase, while that in hydropholic nanopores is less than the bulk phase value. Furthermore, geometric factors, including the characteristic length of pores and the pore shape, significantly affect the effective viscosity. Moreover, it is found that for the pores in the shale formation which are open for imbibition, the proposed model can be applied as the extremely small pores are usually filled with initial water. This work establishes a theoretical foundation to understand fracturing fluid imbibition behavior in shale gas reservoirs, which will benefit the simulation of fluid flow within shale formations at the reservoir scale.

Calibrations of thermo-hydro-mechanical coupling parameters for heating and water-cooling treated granite

Knowledge of thermo-hydro-mechanical (THM) coupling process is important for rock hydrofracturing of enhanced geothermal systems (EGS). The THM coupling parameters (e.g. thermal conductivity, water permeability and Biot’s coefficient, etc) of granite undergoing treatment with heating and water cooling (HWC) were measured using laboratory tests. A large number of cracks inside the granite are caused by the uncoordinated deformation of minerals and the tensile stress induced by the treatment of HWC were clearly observed by scanning electron microscope (SEM), resulting in degradations of physico-mechanical behavior and capacity of heat transmission, and increases of effective stress and connectivity of transport path. Compared with the treatments of heating and natural cooling or heating in real-time in previous studies, the temperature threshold of THM coupling parameters are advanced for HWC treated granite, especially for thermal conductivity, water permeability, Biot’s coefficient and brittle–plastic transition. Prediction models for THM coupling parameters are established based on the correlation analysis. The predictions are in good agreement with the experimental observations. The results are likely to provide an outlet for understanding the characteristics of dry hot rock undergoing hydraulic fracturing or thermal stimulation, especially for the variations and predictions in THM coupling parameters.

Hydraulic Fracture Geometry Modeling Techniques for Extracting Unconventional Reservoirs

This study aims to provide a comprehensive review of all hydraulic fracture geometry modeling techniques available in the conventional and unconventional reservoirs. We are introducing a comparison study between major available hydraulic fracture modeling techniques, advantages, and disadvantages of each one according to the latest related studies. The study includes the three general families of models: 2D models, pseudo-3D models, and fully 3D models. Consequently, the results of this work can be used for selecting the proper model to simulate or stimulate the reservoir to enhance oil recovery using hydraulic fracturing. Also, these results can be used for any future updates related to hydraulic fracturing stimulation based on the comparisons that were conducted.

Geomechanical appraisal and prospectivity analysis of the Goldwyer shale accounting for stress variation and formation anisotropy

Profitable exploitation of unconventional shale gas reservoirs relies on the success of hydraulic fracturing stimulation. This is more likely in brittle rock formations because natural and hydraulic fractures remain open after stimulation, allowing for more hydrocarbon production. Identification of the most favourable depth intervals relies on the robust analysis of available well-logs, and on laboratory-derived mechanical and elastic data obtained under controlled stresses replicating the actual conditions at depth. Beyond their use for predictive geomechanical modelling such laboratory data can act as calibration points for existing well-logs. Well-logs can also be used to guide the selection of the rock samples to be characterised and tested in the laboratory, ensuring that they are representative of the rock formation. Here we apply the above principles and demonstrate how this improves the geomechanical appraisal of the Goldwyer formation and assesses its prospectivity. This workflow integrates Rock-eval geochemical analyses, elastic properties, anisotropy, in-situ stress state and pore pressure, mechanical brittleness and fracturing indices derived from petrophysical and sonic logs in the Theia-1 and Pictor East-1 wells. We estimated an average total organic carbon of 2 w. t.% (maximum 5 w. t.%), a moderate to high dynamic Young's modulus (14–52 GPa), a low Poisson's ratio (0.24–0.27), and an average elasticity-based brittleness index B1 of 41% in the deeper G-III unit. This unit also exhibits a low differential horizontal stress ratio and a high fracture index. Such attributes suggest a good prospectivity of the G-III unit, not only in terms of potential resources but as importantly in terms of fracability.

Breakdown Pressure and Propagation Surface of a Hydraulically Pressurized Circular Notch Within a Rock Material

Rock masses contain pre-existing cracks. These cracks are not usually considered when predicting the maximum injection pressure, i.e. the breakdown pressure, in hydraulic fracture stimulations. The conventional approach to predict breakdown pressure is to use the maximum tensile stress failure criterion to calculate the pressure when a point on the borehole wall reaches the tensile strength of the rock. In addition, a pre-existing crack intersecting a hydraulically pressurized section of a borehole may produce a non-planar crack propagation surface. It is important to predict these non-planar crack propagation surfaces to design productive hydraulic fracturing stimulations and to mitigate risks associated with uncertainties of the resultant crack propagation. To gain a better understanding of this problem, a series of hydraulic fracturing experiments were conducted to investigate the breakdown pressures and crack propagation surfaces of a pressurized circular crack represented by a thin notch, subjected to different external triaxial stresses. The results show that the breakdown pressures under the shear stress conditions studied can be estimated using only the resultant normal stress on the plane of the crack. As the material properties of the experimental specimens are well defined and the crack propagation surfaces were mapped, the experimental results presented in this study provide a very useful measured dataset for the validation of various modelling approaches. The propagation surfaces from experiments were found to align closely to the computational predictions based on the maximum tangential stress criterion. Finally, this study gives evidence in three-dimensions that via the hydraulic fracturing process, the propagation of an initially arbitrarily oriented crack will eventually realign to be perpendicular to the minor principal stress direction.

Engineering-oriented “sweet spot” prediction for tight sandstone gas reservoirs: A case study from Sulige gas field in Western China

Tight sandstone gas reservoirs have the characteristics of low porosity and permeability, deep burial, and low production of vertical wells, which are difficult to predict and exploit. Usually, finding a “sweet spot” requires finding zones with well-developed fractures or easy stimulation by hydraulic fracturing in the later stage. For some tight sandstone gas reservoirs where natural fractures are not developed, directional hydraulic fracturing is a good choice to improve single well production. However, not all reservoirs can achieve the desired productivity after hydraulic-fracture stimulation. In the exploration of the Sulige (SLG) gas field in Western China, sweet spots with strong brittleness and good petrophysical properties can ensure the success of hydraulic fracturing. We have evaluated the SLG gas field to determine how to implement an engineering-oriented sweet spot prediction workflow. The method has five steps: data-quality analysis, lithology prediction, brittleness prediction, petrophysical property prediction, and well planning. We evaluated the feasibility of subsequent sensitive elastic parameter inversion by comparing the accrual and simulated seismic gathers. Then, we used a direct inversion method of Young’s modulus to predict lithology and identify fluid at the same time. Next, we constructed a new brittleness index by combining the rate of change of Young’s modulus and the quartz content to evaluate the brittleness of rocks, which can overcome the shortage of the conventional brittleness index constructed by a single parameter. Finally, by using the brittleness index, we combined the petrophysical properties inversion results to select regions with strong brittleness and good petrophysical properties as the basis of well planning. This workflow achieved remarkable results in the exploration of tight sandstone gas reservoirs in the SLG gas field in Western China.

Fuzzy logic and grey clustering analysis hybrid intelligence model applied to candidate-well selection for hydraulic fracturing in hydrocarbon reservoir

Candidate-well selection (CWS) aims to recognize wells that have potential for higher production after hydraulic fracturing stimulation in petroleum development process, which is natural nonlinear, strong-coupling, uncertain, multi-input, and single-output mathematical problem. CWS hybrid intelligence model is developed by integrating widely applied fuzzy logic systems (FLS), namely, type-2 Takagi-Sugeno-Kang (T2-TSK) FLS, with grey clustering analysis (GCA) for hydraulic fracturing in H gas field of Sichuan Basin, one of the large natural gas field in Southwest of China. The T2-TSK FLS is constructed based on field data involving 49 fractured wells, while the GCA is used to determine the dominant input variables data, and these dominant variables have great influence on post-fractured production. Then we use 39 fractured wells data to train the T1-TSK and T2-TSK FLS to predict post-fractured production. The accuracy of the trained models is validated by comparing predicted post-fractured production with real post-fractured production for the rest of the 10 fractured wells. The evaluation results for the gas field case demonstrate that the T2-TSK FLS is superior to the traditional T1-TSK FLS for CWS using the same input data. The T2-TSK FLS developed in this paper gives high accuracy predicted post-production in H gas field, which is very helpful in selecting the candidate well exactly for hydraulic fracturing.

Automated Microseismic Processing and Integrated Interpretation of Induced Seismicity during a Multistage Hydraulic-Fracturing Stimulation, Alberta, Canada

ABSTRACT The development of organic-rich, low-permeability formations for hydrocarbon production requires the use of unconventional techniques such as multiwell pad drilling of horizontal wells and massive multistage hydraulic-fracturing stimulations. However, proliferation of these unconventional development methods has been linked to localized cases of fault reactivation during or shortly after hydraulic fracturing. In the Duvernay formation, located in Alberta, Canada, induced seismicity from hydraulic fracturing has occurred on nearly vertical strike-slip faults that are difficult to detect with conventional seismic exploration methods. In such cases, faults may only be discernible from seismic events with precise and accurate locations, which generally requires dense seismic monitoring arrays deployed near the stimulated wells. In this study, we introduce a new, semiautomated workflow for processing passive seismic data from a dense array and then integrate it with a 3D seismic dataset to characterize seismicity clusters related to hydraulic fracturing and pre-existing faults. The reactivated faults inferred from the distribution of the microseismic events directly overlie a system of incised, middle Devonian channels below the Duvernay formation observed in time slices extracted from the 3D seismic data. The channel system exhibits a set of lateral offsets, interpreted as ancient strike-slip fault displacements, the detection of which is further enhanced by use of a similarity attribute calculated from the 3D seismic data. Taken together, integrated interpretation of induced seismicity and 3D seismic data support a model of a regional left-lateral strike-slip fault system that was active during the middle Devonian and reactivated in a reverse sense (right-lateral strike slip) during hydraulic-fracturing operations.

A time-field search method for AE source location with a regional velocity model

A time-field search method was proposed for AE event source location, combining the grid search method and the database technique. Theoretical process was given, and laboratory hydraulic fracture stimulation experiments under true-triaxial confining stresses were performed to prove the practicability of the method. A regional velocity model with variable wave velocities and directionality was required to fit observations. The location results showed that time-field location method obtains the global optimal source location solution with a relatively high efficiency and accuracy.

Multifractal Analysis of Acoustic Emissions during Hydraulic Fracturing Experiments under Uniaxial Loading Conditions: A Niutitang Shale Example

Fracture characterization is essential for estimating the stimulated reservoir volume and guiding subsequent hydraulic fracturing stimulations in shale reservoirs. Laboratory fracturing experiments can help provide theoretical and technical guidance for field operations. In this study, hydraulic fracturing experiments on the shale samples from Niutitang Formation in Hunan Province (China) under a uniaxial loading condition are conducted. The multifractal method is used to analyze the acoustic emission (AE) signals and characterize fracture initiation and propagation. The hydraulic fracturing process can be divided into three stages based on the characteristics of AE signals: the initial stage, the quite stage, and the fracturing stage. The multifractal analysis results showed that: (1) the value of the spectrum width, Δα, continues to increase as the energy accumulates until the fracturing stage starts; and (2) the difference in the multifractal spectrum values, Δf, reflects the relationship between small and large signal frequencies and can quantify the fracture scale, i.e., the lower the Δf, the larger the fracture scale and vice versa. The results were further verified using a time-frequency analysis of the AE signals and micro-CT scanning of the samples. This study demonstrates that the multifractal method is feasible for quantitatively characterizing hydraulic fractures and can aid field hydraulic fracturing operations.

Forecasting shale gas performance using the Connected Reservoir Storage Model

Characterized by rock sediments and complicated storage mechanisms, shale reservoir development is to create flow systems comprised of complex natural fissures and hydraulic fracture stimulation such that the hydrocarbons in the reservoir can be recovered economically. The prediction of shale reservoir production performance is critical for reservoir management and challenging due to the compounding nature of multiple flow mechanisms one encounters during the life of a shale gas well. Given empirical nature, many models based on curve-fitting historical production data prone to inaccurately forecast well's rates in shale gas reservoirs, particularly when the production history of a well is short. This paper further extends the applicability of the Connected Reservoir Storage Model (CRSM) to shale reservoirs. The CRSM was derived from diffusivity theory by using historical production rate and bottomhole flowing pressure (BHFP) to determine the reservoir behavior and unit pressure response, and it can be conveniently used to predict production performance under variable operating conditions. The CRSM is mathematically robust and easy for application since it can be determined with limited reservoir information without knowing the reservoir geometry or reservoir permeability. This study uses the operational history of a shale gas well to demonstrate the CRSM's capability in rate prediction and couples the model with stochastic methods to approximate the most probable outcome under variable operating conditions.

Connectivity of pores in shale reservoirs and its implications for the development of shale gas: A case study of the Lower Silurian Longmaxi Formation in the southern Sichuan Basin

The unconnected gas-bearing pores in shale gas reservoirs may be transformed into “potential recoverable pores” after large scale hydraulic fracturing. However, the mainstream pore classification methods of shale gas reservoirs, do not take the unconnected pores into account, which impacts the evaluation accuracy of reservoir pore effectiveness. To solve this problem, this paper took the shale of Lower Silurian Longmaxi Formation in the southern Sichuan Basin as the research object to carry out experiments on core porosity, centrifugal + gradual drying NMR after saturated with brine and NMR freeze–thaw using plunger samples and crushed samples to analyze the volume, main development location and main pore size distribution range of unconnected pores. Then, the pore systems were classified, and the lower limit of effective pore size of connected gas-bearing pores was determined. Finally, the total pore effectiveness of shale gas reservoirs was evaluated, and the influence of unconnected pores on the development of shale gas was discussed. And the following research results were obtained. First, there are a large number of unconnected pores in the shale gas reservoirs of the study area, accounting for 30.23%. Most of them are mainly developed in organic matters and a few are developed in clay minerals. The distribution of pore size ranges from 5 nm to 30 nm. Second, T2 cut-off value of clay bound water in the shale gas reservoirs of the study area is 0.26 ms, whose corresponding pore size is 5.35 nm, which is the lower limit of the effective pore size. Third, large-scale hydraulic fracturing can improve the unconnected pores with the size more than 5.35 nm, so effective development of shale gas will be realized. Fourth, after hydraulic fracturing stimulation, the unconnected pores can increase the storage space of fracturing fluid in the matrix, absorb the fracturing fluid in the fractures, replace the shale gas in the pores and promote the automatic alleviation of water lock in shale gas reservoirs, so the single-well shale gas production will be increased. In conclusion, fluid occurrence and pore system in shale pores can be quantitatively divided by means of centrifugal + gradual temperature drying method combined with NMR experiments, mobile water and capillary bound water can be determined by the high speed centrifugal + NMR experiments, and capillary bound water and clay bound water can be determined by the gradual drying + NMR experiments.

Characterization of the unconventional Tuscaloosa marine shale reservoir in southwestern Mississippi, USA: Insights from optical and SEM petrography

This study presents new optical petrography and electron microscopy data, interpreted in the context of previously published petrophysical, geochemical, and mineralogical data, to further characterize the Tuscaloosa marine shale (TMS) as an unconventional reservoir in southwestern Mississippi. The basal high resistivity zone has a higher proportion of Type II sedimentary organic matter than the overlying TMS, indicating it is more prone to oil generation. Optical petrography and electron microscopy reveal a heterogeneous clay matrix with ubiquitous pyrite grains, quartz, feldspar, glaucony, foraminifera, shell fragments, and rarer occurrences of apatite and crinoid fragments as well as liptinite, alginite, inertinite, and vitrinite. Our petrographic observations suggest that higher abundances of detrital quartz grains coupled with minimal authigenic cements result in higher porosity and permeability. However, the TMS is also more clay-rich than other unconventional shale oil and gas plays, which can impair the effectiveness of hydraulic fracture stimulation. Thin section observations reveal alternating clay and calcium carbonate laminae that are interpreted to reflect changes in sediment flux. Planktonic foraminifera indicate an overlying oxygenated water column while benthic inoceramid fragments and pervasive authigenic pyrite suggest anoxic or dysoxic bottom water conditions. Apatite fragments in thin section suggest mixing events and an influx of nutrient-rich sediments. Overall, these observations suggest that a variety of paleodepositional environments occurred in the TMS and the lithofacies diversity resulting from these small-scale depositional cycles makes it difficult to determinatively identify areas conducive to enhanced economic hydrocarbon recovery.

Analysis of the Difference between Hydraulic Fracturing and Flow Channel Fracturing

As time goes by, there will be a decline in formation productivity, as reflected in the decline in the rate of oil production from production wells. The decline in the rate of production was caused by many things such as a decrease in reservoir pressure, also formation damage. Where damage to the formation will result in a decrease in rock permeability. The decrease in rock permeability is caused by the blockage of rock pores due to the invasion of solids and drill mud filtrate, cementing, fluid fluids or previous stimulation. Besides the small rate of oil production can also be caused by the low natural permeability of rocks. With the decreasing productivity of the formation, it is necessary to make efforts to increase the productivity of the formation again, where one of them is by the method of hydraulic fracture stimulation. In this analysis, we will discuss the difference between conventional stimulation methods and flow channel fracturing. Flow channel fracturing is a fracturing process by making a network around proppant granules to form proppant pillar, so that a path is formed for the fluid to flow more easily. What distinguishes between conventional hydraulic fracturing with flow channel fracturing is the resulting fracture form, fracturing fluid injection pattern, and the amount of proppant used.

Stimulation Techniques of Coalbed Methane Reservoirs

Coalbed methane (CBM) plays an important role in securing world energy supply and transiting electricity generation from fossil fuel to renewables. CBM reservoirs are generally very tight and require effective stimulation to achieve economic extraction. In recent years, an increasing number of coal seam stimulation techniques were developed, but selecting the most suitable stimulation technique for a particular CBM reservoir condition is becoming increasingly challenging. Therefore, it is deemed very important to compare the effectiveness of different stimulation techniques in a meaningful way to guide future research directions in this area. In this paper, the stimulation techniques were firstly classified into different categories according to the stimulation mechanisms. Then, the associated principles, the history of advances, and challenges of different stimulation techniques were comprehensively reviewed. Two indexes were proposed to compare the stimulation effectiveness at the laboratory and field scales, respectively. Finally, the comparison and evaluation of each stimulation technique in respect to the stimulation effectiveness, influence range, duration, and environment were conducted in detail; the cryogenic liquid nitrogen stimulation technique receives the highest total score among the discussed laboratory-scale stimulation techniques. Hydraulic fracturing and gas injection stimulation techniques gain the highest total score among key field-scale stimulation techniques. Considering the time required for each stimulation method to take effect, high-voltage electric fracturing may have a greater potential in the future. This work is expected to help better select the optimal stimulation technique for reservoir specific conditions.

Numerical evaluation of a fracture acidizing treatment in a three-dimensional fractured carbonate reservoir

A fracture acidizing treatment, as an effective way to enhance the well performance, is commonly used in fractured carbonate reservoirs operated with hydraulic fracturing stimulation. A fracture acidizing simulator is developed to model the fracture acidizing process in a fractured carbonate rock mass embedded with randomly distributed natural fractures. Mathematical models incorporating the hydro-chemical coupled process together with the material compressibility are discretized based on a unified pipe-network method. An implicit time scheme is employed in the proposed simulator, and the model reliability is verified against the results obtained from a commercial software. Sensitivity analyses are carried out in respect of the Sherwood number, matrix porosity, and closure stress considering the acidizing along a single hydraulic fracture in a carbonate domain. The proposed model is applied to the simulation of the fracture acidizing considering highly interconnected fracture network system. Two stages in the production estimation, the oil development with constant production rate in the first stage and with constant bottom-hole pressure in the second stage, are operated. It is concluded that the increase of either the injection concentration or the injection pressure in the acidizing treatment process achieves better acidizing efficiency and thus improves the productivity potential.

The natural gas sector needs to be mindful of its sustainability credentials

Despite substantial growth in demand for natural gas, building of infrastructure and prevailing low wholesale prices, some energy-industry stakeholders are now questioning the long-term sustainability of the natural gas industry. This is due, in part, to it being a fossil fuel with associated greenhouse gas emissions, and its very poor long-term historical track record regarding gas flaring and fugitive methane and other light-hydrocarbon gas emissions. However, major environmental concerns have also arisen regarding the development of unconventional natural gas resources using hydraulic fracture stimulation, its large environmental and community impacts, water usage and potential contamination and induced seismic activity leading to increased surface impacts. There are however a number of technological opportunities identified and available for deployment for a number of years that could enable the industry to improve its sustainability credentials. Seriously developing these opportunities could convince public opinion that the natural gas sector should be part of long-term plans to develop and maintain a near-zero emissions energy sector. Most of the identified opportunities are obvious, such as eliminating flaring, improving production efficiency by gaining a better understanding of sub-surface reservoirs and fluid movements, and reducing its surface footprints, carbon capture sequestration and utilization, and more collaboration with the renewables sector to build hybrid power and energy storage plants. It is imperative for the natural gas sector’s long-term future that it fully embraces these opportunities and makes them visibly contribute to more eco-friendly energy supply-chain developments. Cited as : Wood, D.A. The natural gas sector needs to be mindful of its sustainability credentials. Advances in Geo-Energy Research, 2020, 4(3): 229-232, doi: 10.46690/ager.2020.03.01

Impact of geomechanics in coal bed methane development and production, Barakar coals in central India

Geomechanics plays a critical role in the different stages of coal bed methane (CBM) operations, starting from its development through production to its abandonment as in Sohagpur field of central India. In general, higher gas production has been observed from the coal seams in low-stress regimes compared to high-stress regimes; however, during the CBM development planning, stress information has been overlooked. The need for inclined and horizontal wellbores in coal seams has increased due to their many-fold rise in production when compared to vertical wells with a minimum surface footprint. However, these non-vertical wells have wellbore instability issues leading to high nonproductive time (NPT) during drilling and completion operations. Prolong challenges exist in achieving the desired half-length from hydraulic fracturing (HF) stimulation due to the limited understanding of the stress contrast between target coal and bounding lithology. The permeability of the coal reservoir varies greatly during depletion due to the combined effects of effective stress and matrix shrinkage. These effects directly impact productivity and hence, require a detailed understanding of how permeability varies during production life. In many instances, production from coal seams is complicated and unpredictable because of the influence of stress induced natural fractures. A geomechanical earth model is focused on understanding and mitigating the aforementioned challenges. In addition to coal thickness and gas content, stress-permeability maps are prepared to assist in the development program to prioritize wells in lower and moderate stress areas. Wellbore stability analysis has been carried out using calibrated stress and strength profiles along with other rock mechanical inputs to successfully drill high angle wells. This analysis indicates that with a slightly higher mud weight, high angle and horizontal wells can be drilled successfully. Hydraulic fracturing design incorporating the available stress contrast can help in achieving the desired fracture parameters without height growth. The coal permeability model suggests that during depletion, coal permeability is expected to increase by about 1.2–3.5 times with a positive impact on productivity. Critically stressed fracture analysis has been carried out on mapped fractures, which suggest that about 48% of the natural fractures are in a stressed state. Presence of these natural fractures has a positive (faster dewatering) as well as a negative (external water) impact on productivity at different places in the study area.