Fractured Gas Research Articles

Phase Behavior and Rational Development Mode of a Fractured Gas Condensate Reservoir with High Pressure and Temperature: A Case Study of the Bozi 3 Block

The Bozi 3 reservoir is an ultra-deep condensate reservoir (−7800 m) with a high temperature (138.24 °C) and high pressure (104.78 MPa), leading to complex phase behaviors. Few PVT studies could be referred in the literature to meet such high temperature and pressure conditions. Furthermore, it is questionable regarding the applicability of existing condensate production techniques to such a high temperature and pressure reservoir. This study first characterized the phase behavior via PVT experiments and EOS tuning. The operating conditions were then optimized through reservoir numerical simulation. Results showed that: (1) the critical condensate temperature and pressure of Bozi 3 condensate gas were 326.24 °C and 43.83 MPa, respectively; (2) four gases (methane, recycled dry gas, carbon dioxide, and nitrogen) were analyzed, and methane was identified as the optimal injection gas; (3) gas injection started when the production began to fall and achieved higher recovery than gas injection started when the pressure fell below the dew-point pressure; (4) simultaneous injection of methane at both the upper and lower parts of the reservoir can effectively produce condensate oil over the entire block. This scheme achieved 8690.43 m3 more oil production and 2.75% higher recovery factor in comparison with depletion production.

Three-dimensional coupled vibration failure analysis and structural optimization of the crankshaft of the diesel engine used in the shale gas fracturing truck

The crankshaft is the key component of the shale gas fracturing truck's diesel engine. Mass imbalance due to errors in the manufacturing process and other damage caused by long periods of operation can cause vibration for the crankshaft vibration problem. The static analysis is carried out based on the ignition condition of the second cylinder. The modal analysis of the crankshaft is then carried out. The modal analysis showed that resonance could cause significant deformation of the crankshaft. Consequently, harmonic response analysis, stochastic vibration analysis, and topology optimization were carried out on the crankshaft. The results show that the modes of each order of the crankshaft of the fracturing truck diesel engine are diverse. The modal amplitude is large. Fatigue damage is easily generated. After optimization, the mass of the crankshaft is reduced, the first natural frequency is increased, and the crankshaft is far away from the resonance interval while avoiding resonance failure. This document provides theoretical guidance for the design, optimization, research, and development of crankshafts.

Modelling of enhanced gas extraction in low permeability coal seam by controllable shock wave fracturing

The controlled shock wave (CSW) fracturing is an effective method for enhancing permeability of coal seam to promote gas extraction. Based on Fick’s law, Darcy’s law, the ideal gas law and the Langmuir equation, a damage-seepage-deformation coupling mathematical model of CSW fracturing in coal seam combined with the maximum tensile stress and the Mohr-Coulomb criterion is established. This model is implemented into COMSOL Multiphysics to simulate the coal seam CSW fracturing and subsequent gas extraction. When the shock wave and isotropic in-situ stress are applied on the borehole wall, the coal damage zone is an annular shape, and the permeability in the damage zone increases sharply. The CSW can effectively increase the efficiency of gas extraction and reduce the gas pressure and gas content in coal seam. With the increase of CSW action times, the damage in coal mass reaches a threshold and tends to be stable after several shocks. The damage area and the gas extraction efficiency are positively correlated with the shock intensity. Under the anisotropic ground stress, the larger diversity of the stress in different directions is, the more obvious damage extension in the fractured coal along the maximum stress direction is. Ground stress can inhibit the extension of cracks in the CSW fractured coal seam. This inhibition effect becomes more obvious with the increase of in-situ stress. Parameters are substantiated of controlled shock wave impact on the coal seam, which ensures increased methane extraction from low-permeability reservoirs, are substantiated.

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

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

Research on Enhancing Gas Extraction Efficiency through CO2 Gas Fracturing in Outburst-Prone Coal Seams.

Given the background of significant Coal Mine gas disasters worldwide, the research and development of efficient gas control technologies have become critical to ensuring mining safety. CO2 gas fracturing (CO2-Frac), an innovative technology for Coal Mine gas control, has demonstrated efficiency in various mining areas across China. However, its application in outburst-prone coal seams is not yet fully understood. This study presents a field-scale CO2-Frac project conducted in an outburst Coal Mine in China, specifically the Pingshu Coal Mine, where the previously employed dense-borehole gas extraction technology failed to efficiently achieve gas extraction and outburst prevention. The CO2-Frac plan was evaluated through fracture propagation experiments utilizing both single-hole and dual-hole configurations, highlighting the advantages of the dual-hole CO2-Frac method. Subsequently, on-site gas extraction tests were conducted to further assess the efficacy of the CO2-Frac plan. The results indicate that (1) In the dual-hole CO2-Frac scheme, the fractured and pressure relief area expanded to approximately 26.82 m2, which is 220% larger than that of the single-hole scheme. (2) The dual-hole CO2-Frac significantly enhanced gas extraction effectiveness, increasing the flow rate from 0.026 to 0.216 m3/min in a 100m borehole, a 7.3-fold improvement. Additionally, the gas extraction period to reach the standard was reduced from 20 to 6 days. These findings conclusively demonstrate that the dual-hole CO2-Frac technique is an effective method for safe excavation in outburst-prone coal seams, providing both theoretical and practical validation for its application in similar geological settings.

Optimization of pressure management strategies for geological CO2 storage using surrogate model-based reinforcement learning

Injecting greenhouse gas (e.g. CO2) into deep underground reservoirs for permanent storage can inadvertently lead to fault reactivation, caprock fracturing and greenhouse gas leakage when the injection-induced stress exceeds the critical threshold. It is essential to monitor the evolution of pressure and the movement of the CO2 plume closely during the injection to allow for timely remediation actions or rapid adjustments to the storage design. Extraction of pre-existing fluids at various stages of the injection process, referred as pressure management, can mitigate associated risks and lessen environmental impact. However, identifying optimal pressure management strategies typically requires thousands of simulations, making the process computationally prohibitive. This paper introduces a novel surrogate model-based reinforcement learning method for devising optimal pressure management strategies for geological CO2 sequestration efficiently. Our approach comprises of two steps. The first step involves developing a surrogate model using the embed to control method, which employs an encoder-transition-decoder structure to learn dynamics in a latent or reduced space. The second step, leveraging this proxy model, utilizes reinforcement learning to find an optimal strategy that maximizes economic benefits while satisfying various control constraints. The reinforcement learning agent receives the latent state representation and immediate reward tailored for CO2 sequestration and choose real-time controls which are subject to predefined engineering constraints in order to maximize the long-term cumulative rewards. To demonstrate its effectiveness, this framework is applied to a compositional simulation model where CO2 is injected into saline aquifer. The results reveal that our surrogate model-based reinforcement learning approach significantly optimizes CO2 sequestration strategies, leading to notable economic gains compared to baseline scenarios.

Analysis of Production Decline Type Curves Considering Water Influx in Naturally Fractured Gas Reservoirs

Abstract In the development of fractured gas reservoirs with edge and bottom water, water invasion is a pervasive issue. However, most production decline analysis models focus on primary depletion with closed boundaries rather than secondary depletion with water influx. Therefore, this paper aims to develop decline type curves for analyzing and interpreting production data from existing natural water influx in fractured gas reservoirs. Firstly, a transient dual porosity flow model is developed considering water influx in naturally fractured gas reservoirs, the functions of Blasingame decline type curves are derived and obtained. Subsequently, the Blasingame production decline type curves of a vertical well in naturally fractured reservoirs experiencing natural water influx are plotted. These new type curves can estimate water invasion and dual medium parameters, offering valuable insights for production decline analysis in fractured reservoirs with water influx. The Blasingame production decline curves are divided into six regimes based on characteristics. Then, the effects of various formation parameters and water invasion cases on the type curves are discussed and analyzed. Compared with Blasingame type curves without water influx at the external boundary, the behaviors of those presented in this paper are quite different at the boundary responses. Finally, through the analysis of a case well, it is found that theoretical type curves considering dual-medium and water invasion are more consistent with actual production data. This suggests that these new type curves provide more accurate estimation for understanding and managing issues related to water invasion in fractured gas reservoirs.

Drilling Fluid Density Optimization for Narrow Density Window Fractured Formation

Abstract Fractures are prevalent in the Leikoupo Formation in western Sichuan, with a narrow safe density window of 0.06-0.12 g/cm3, leading to frequent downhole accidents like kicks and losses. Using Pengzhou X well as a case study, this research employed numerical simulation to analyze the impact of various drilling fluid densities within this window on displacement rate and bottomhole pressure. It established an optimal drilling fluid density model for fractured formations with narrow density windows. Findings reveal that as drilling fluid density increases, annulus up-return velocity decreases, potentially trapping fracture gas in the upper annulus. Optimal drilling fluid density lies within this narrow window, maintaining a dynamic balance between preventing fast gas return and fluid accumulation in fractured formations. The model applied to Pengzhou Y well yields a drilling density correlation of 0.000001036, consistent with optimized model results. This approach optimizes drilling fluid density within narrow density windows, mitigating downhole gushing and leakage accidents.

Numerical study of the effects of loading parameters on high-energy gas fracture propagation in layered rocks with peridynamics

The objective of this study is to investigate the influence of loading parameters on the propagation pattern of high-energy gas fractures in layered rock formations. To this end, a peridynamic model for brittle rock accounting for material heterogeneity was proposed. The ability of the model to simulate dynamic fractures was validated through laboratory experiments, and the homogeneity coefficient for the critical elongation rate was calibrated. On this basis, a numerical model of high-energy gas fracturing in layered rocks containing interfaces was constructed. Simulations were conducted to analyse high-energy gas fracturing from cylindrical intact boreholes and perforated boreholes under varying loading parameters. The results indicate that as the loading rate increases, the number of radial fractures surrounding the borehole gradually increases, whereas the influence of in-situ stress on fracture propagation diminishes. When the loading rate is fixed, both an increase in the peak pressure and a decrease in the decay rate are conducive to enhancing the propagation length of fractures. The propagation speed of fractures significantly decreases when they reach an interface but recovers after they penetrate it. Fractures tend to penetrate an interface when the angle of approach is closer to a right angle, and the direction of fracture propagation can be controlled through a perforation design. These findings provide valuable insights into the selection and optimization of loading parameters for reservoir stimulation via high-energy gas fracturing.

Study on Safety Tunneling Technology of Secondary Outburst Elimination by CO2 Gas Fracturing in High-Outburst Coal Seam

The No. 3 coal seam in the Yuxi Coal Mine has a measured maximum gas content of 25.59 m3/t, along with a maximum gas pressure of 2.9 MPa, indicating its high risk to gas and outbursts. To mitigate outburst risks of the coal seam, the 1301 working face has been implemented with gas pre-drainage measures by grid boreholes from underlying roadways. After one year of extraction, it was confirmed that the gas content at all 33 test sites was below 8 m3/t, meeting the outburst prevention standards. However, during subsequent coal tunnel excavation, the gas desorption index K1 value frequently exceeded the standard, resulting in numerous occurrences of abnormal gas emission or small-scale outbursts. To tackle the challenges associated with safe excavation following the first-round regional outburst prevention measures, a research and industrial trial of CO2 gas fracturing (CO2-Frac) technology for secondary outburst prevention and rapid excavation was completed. The results show that the dual-hole and high-pressure (185 MPa) CO2-Frac considerably contributes to outburst prevention. K1 exceedances per hundred meters of tunnel excavations were from an average of 2.54 without CO2-Frac to an average of 0.28 after the new technology was implemented, leading to an eight-fold reduction. Additionally, the monthly excavation footage increased from an average of 81.64 m without CO2-Frac to an average of 162.42 m with CO2-Frac, resulting in a two-fold improvement. The dual-hole and high-pressure CO2-Frac is an advanced technology for safe and efficient excavation for secondary outburst elimination in highly outburst-prone coal seams in the Yuxi Coal Mine, with potential for widespread application in similar coal seam conditions.

Augmented Depletion Development Technology Assessed Across US Shale Plays

_ This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 217792, “Assessment of Augmented Depletion Development Technology Across US Shale Plays,” by Ahmed Merzoug, SPE, Texas A&M University, and Vibhas J. Pandey, SPE, ConocoPhillips. The paper has not been peer reviewed. _ The concept of augmented depletion development (ADD) was introduced to the industry through a pilot project conducted in the Bakken play in the US. These wells are openhole wells drilled within the fractured network of a pad. They are not fracture stimulated deliberately but do produce and contribute to the overall production of the lease. In this study, numerical modeling is used to understand the potential performance of these wells in several plays across the US. The learnings from this study can be used as a benchmark for operators that are planning on implementing such wells in their field development programs. Theoretical Basis of Study The concept of ADD can be modeled using a similar approach to the analytical solutions developed for flow into a multistage fractured horizontal well. In these wells, several regimes can be identified, such as transient linear flow and boundary-dominated flow. In previous work in the literature that proposed a method for analyzing production data of linear flow of fractured gas wells, fractures were assumed to have infinite dimensionless conductivity. Those researchers proposed a solution for a constant bottomhole-pressure liquid flow that is described in the present complete paper by a series of equations. For the case used by the present authors, a well spacing of 300 ft is assumed, implying that the perpendicular distance from the wellbore to a corresponding boundary is 150 ft, which is half the spacing between the fractured well and the ADD well (assuming each well drains half the fracture length). To elaborate further for better understanding of production, a plot of product of cumulative dimensionless rate and formation permeability (as a proxy for cumulative rate) while assuming all other properties behave the same shows that, with higher permeability, the recovery potential not only increases but also appears to accelerate. This supports the concept that, during the time of production of ADD wells, it is preferable to have higher permeabilities that can support faster production in zones that the primary wells may not drain effectively. The results of the analytical equation are for only one fracture but can be readily extended to multifractured horizontal wells using superposition methods. Methodology This study uses physics-based numerical modeling to simulate the performance of ADD wells in different plays. The numerical code simulates wellbore flow, hydraulic fracturing, geomechanics, and reservoir flow, all in the same package. The fracture and reservoir mesh are independent. The flow between the matrix and the reservoir is calculated using the 1D submesh approximation to reduce the computation expenses with higher accuracy. The hydraulic fracturing propagation algorithm uses a tip-tracking algorithm to allow the use of larger grid size without compromising accuracy in layered formations. The fracture conductivity is calculated with stress changes. The conductivity profile changes from a propped fracture into an unpropped fracture. The unpropped fracture conductivity is an underlying assumption used in this study. The collision between fractures initiated from different wells also is an assumption in this study.

Numerical Simulation of Non-Darcy Flow in Naturally Fractured Tight Gas Reservoirs for Enhanced Gas Recovery

In this work, we analyze non-Darcy two-component single-phase isothermal flow in naturally fractured tight gas reservoirs. The model is applied in a scenario of enhanced gas recovery (EGR) with the possibility of carbon dioxide storage. The properties of the gases are obtained via the Peng–Robinson equation of state. The finite volume method is used to solve the governing partial differential equations. This process leads to two subsystems of algebraic equations, which, after linearization and use of an operator splitting method, are solved by the conjugate gradient (CG) and biconjugate gradient stabilized (BiCGSTAB) methods for determining the pressure and fraction molar, respectively. We include inertial effects using the Barree and Conway model and gas slippage via a more recent model than Klinkenberg’s, and we use a simplified model for the effects of effective stress. We also utilize a mesh refinement technique to represent the discrete fractures. Finally, several simulations show the influence of inertial, slippage and stress effects on production in fractured tight gas reservoirs.

Mechanism and application of gas phase trapping by spontaneous imbibition

For fractured gas reservoirs with strong water drive, gas phase trapping affects the gas recovery significantly. The recovery may be less than 50% for some reservoirs while it is only 12% for Beaver River gas field. The gas phase trapping mechanism has been revealed by the results of depletion experimental test. The residual pressure of the trapped gas is as high as 11.75 MPa with a 12.8 cm imbibition layer resulting in gas recovery deceased 49.5% compared with that without imbibition layer. A mathematical model is built to calculate the imbibition thickness based on capillary pressure and relative permeability of the matrix. The gas phase trapping are analyzed by two representative wells in Weiyuan gas field, the intermittent production reinforces the imbibition thickness and result in gas trapped in the matrix block with high residual pressure for the low performace gas wells, the extremely low gas recovery can be explained more rationally. That lays a foundation of improving the gas recovery for fractured reservoirs.

Comprehensive analysis of the effect of structural parameters on erosion wear, structural stress, and deformation of high-pressure double-elbow in shale-gas fracturing

In field hydraulic fracturing operation of shale gas development, the high pressure and large displacement liquid-particle two-phase fracturing fluid can be forced to change direction many times through high-pressure double-elbow, and be transported from the outlet pipeline of the fracturing pump to the main pipeline. The high-pressure double-elbow is prone to be affected by erosion wear and Fluid-Structure Interaction (FSI), resulting in perforation and fracture, posing a potential safety threat to field operation. In this study, we conducted the erosion wear experiments on 35CrMo steel used for high-pressure double-elbow in shale-gas fracturing. The erosion rates under different impact angles and flow velocities were obtained, and proposed a novel model of erosion prediction for high-pressure double-elbow. Then the numerical investigation was employed to conduct a comprehensive analysis of erosion wear, structural stress and deformation by the coupling of Computational Fluid Dynamics (CFD) and Finite Element Analysis (FEA). The effects of structural parameters such as connection straight pipe length, pipe inner diameter and fluid turning direction were discussed. The results indicate that with the increase of connection straight pipe length, the flow erosion decreases first then varies little, and the deformation gradually increases. Slight erosion wear but large structural stress and deformation in major inner diameter pipe. And the minimum degree of erosion and flow-induced deformation present with the fluid turning direction of double-elbow as 0°. The study can provide references for the design, installation and detection of high-pressure double-elbow and ensure safety in the process of shale gas fracturing.

Experimental Investigation on Condensate Revaporization During Gas Injection Development in Fractured Gas Condensate Reservoirs

Experimental Investigation on Condensate Revaporization During Gas Injection Development in Fractured Gas Condensate Reservoirs

In-situ CT study on the effect of cyclic gas injection and depletion exploitation on the phase behavior of fractured condensate gas reservoirs

Using subterranean rock cores as samples, the impact of depletion exploitation and cyclic gas injection on the occurrence and dynamic utilization of condensate oil and the damage to reservoirs were studied. Initially, the internal pore structure of the rock core was analysed using computer tomography (CT), followed by depletion and cyclic gas injection experiments, with in-situ CT scanning of the samples. The results indicate that under different fracture apertures, condensate oil exhibits wave flow and slug flow states. The production effectiveness of cyclic gas injection is significantly superior to depletion exploitation production, with condensate oil saturation decreasing by over 30%. During cyclic gas injection, fractures serve as the main flow channels, with condensate oil being extracted first. In cyclic gas injection, the most significant effect is seen during the first injection, with a decrease in oil saturation of around 3%. Subsequent injections show decreases of approximately 1% and 0.5% in oil saturation respectively. As the gas injection volume increases, the extent of cumulative production rate improvement also gradually increases; however, once the injection volume reaches the reservoir pressure, the rate of cumulative production rate improvement will gradually decrease. These findings provide technical support for optimizing the development mode of condensate gas reservoirs, clarifying the seepage law of condensate oil and gas, and providing technical support for the efficient development of fractured condensate gas reservoirs.

Fracturing Construction Curves and Fracture Geometries of Coals in the Southern Qinshui Basin, China: Implication for Coalbed Methane Productivity.

Hydraulic fracturing technology has become a common practice to enhance the permeability of coal seams, and its effectiveness significantly impacts the productivity of coalbed methane (CBM) wells. In this study, multiple data sets, including fracturing reports, productivity data, and microseismic monitoring, were utilized to analyze the factors influencing fracturing effectiveness and gas well production at the southern margin of the Qinshui Basin, China, especially the Zhengzhuang and Fanzhuang blocks. Statistics revealed that the fracturing displacement, liquid consumption, and sand consumption were 8 m3/min, 17.69-1386.52 m3 (averaging 728.42 m3), and 28.5-46.1 m3 (averaging 40 m3), respectively. There were differences in the types of fracturing curves among blocks or well groups, and the natural fracture system was identified as the key factor affecting their characteristics. The coal seams with high density of microfractures in Zhengzhuang reduce the fracture threshold of reservoirs during hydraulic fracturing, resulting in a lower fracture response ratio than that of Fanzhuang (71.0 vs 80.3%). Well groups with higher microfracture width in coal seams (Group-ZC and DS) experienced a further reduction in fracture response (averaging 67.2 vs 80.3%), and the connection of hydraulic fractures (HFs) with these high-permeability microfractures lead to an increase in the proportion of fluctuating fracturing curves (averaging 52.2 vs 33.6%). Regional structural features and fracturing effectiveness jointly affected the production of CBM wells. The productivity in Zhengzhuang was lower than that in Fanzhuang due to the highly developed faults and deeply buried coal seams. Shallow coal seams with a high width of microfractures and a low-stress environment were easily supported by a proppant, forming a complex HF network and yielding a high productivity (Group-ZC and DS). For other deeper well groups, proppant migration became unfavorable once high-angle and complex branch HF clusters formed in coal seams, leading to local low-efficiency wells and fluctuating fracturing curves.

Rate Transient Analysis for Multi-Fractured Wells in Tight Gas Reservoirs Considering Multiple Nonlinear Flow Mechanisms

Making rate transient analysis (RTA) and formation evaluation for multi-fractured tight gas wells has always been a difficult problem. This is because the fluid flow in the formation has multiple nonlinear flow mechanisms, including gas-water two-phase flow, gas slippage, low-velocity non-Darcy flow, and stress-dependent permeability. In this paper, a novel RTA method is proposed for multi-fractured wells in tight gas reservoirs incorporating nonlinear flow mechanisms. The RTA method is based on an analytical model, which is modified from the classical trilinear flow model by considering all the nonlinear flow mechanisms. The concept of material balance time and normalized rate is used to process the production data for both water and gas phases. The techniques of approximate solutions in linear/bilinear flow regimes and type curve fitting are combined in the proposed RTA method. After that, the rate transient behaviors and influencing factors of multi-fractured tight gas wells are analyzed. A field case from Northwestern China is used to test the efficiency and practicability of the proposed RTA method. The results show that six flow regimes for both gas and water production performances are exhibited on the log-log plots of normalized production rate against material balance time. The rate transient responses are sensitive to the nonlinear flow mechanisms, and formation and fracture properties. The medium flow regimes are significantly affected by fracture number, fracture conductivity, fracture half-length, stress-dependent permeability, gas-water two-phase flow, and formation permeability, which should be considered in making RTA of fractured tight gas wells. The field case shows that both gas and water production performances can be well-fitted using the proposed RTA method. The major innovation of this paper is that a novel RTA method is proposed for fractured tight gas wells considering multiple nonlinear flow mechanisms, and it can be used to make reasonable formation and fracturing evaluations in the field.

Underground hydrogen storage in depleted gas reservoirs with hydraulic fractures: Numerical modeling and simulation

Underground hydrogen storage (UHS) is one of the key technological solutions for balancing energy systems and promoting sustainable energy development. In this study, we propose a novel UHS method, which involves injecting hydrogen generated from electrolyzing formation water into depleted gas reservoirs through hydraulic fractures during off-peak electricity periods, and then efficiently producing hydrogen for power generation during peak electricity periods. We establish a numerical simulation model for UHS in a depleted fractured gas reservoir, covering the entire process from injecting hydrogen gas into the reservoir through wells to shutting them down and subsequently producing hydrogen when required. We then investigate the impact of hydrogen injection rate, injection duration, and shut-in duration on the UHS process and storage efficiency. Our findings reveal that hydrogen production efficiency can exceed 85 % by optimizing hydrogen injection and production strategies. Our study provides an exemplary numerical simulation scheme to evaluate the feasibility of UHS in depleted gas reservoirs with hydraulic fractures.

An Artificial Neural Network Model for a Comprehensive Assessment of the Production Performance of Multiple Fractured Unconventional Tight Gas Wells

The potential of unconventional hydrocarbon resources has been unlocked since the hydraulic fracturing technique in combination with long horizontal wells was applied to develop this type of reservoir economically. The design and optimization of the fracturing treatment and the stimulated reservoir volume and the forecasting of production performance are crucial for the development and management of such resources. However, the production performance of tight gas reservoirs is a complicated nonlinear problem, described by many parameters loaded with uncertainty. The complexity of the problem influences and inspires the sophistication of the solution to be used. This paper proposed an artificial network model that allows for fast, extended, and accurate analyses of the production performance of multiple fractured unconventional tight gas wells. In the comprehensive approach developed, the reservoir rock parameters, the drainage area, and the hydraulic fracture parameters are treated as a variable input to the model. The analysis is no longer constrained by fixed “shoes box” geometry, and the values of the parameters defining the reservoir and stimulated volume are not limited to a few discrete values. The numerical experiment used to construct a database for model development was designed using a genetically optimized Latin hypercube sampling technique. A special approach was used in the preparation of “blind data”, which are crucial for truly reliable model verification. In the result, a developed tool offers an extended rock-fluid description, flexible model, and stimulated reservoir volume dimensioning and parameterization, as well as a high degree of applicability in sensitivity analysis and/or optimization.