Hydraulic Fracture Optimization Research Articles

Propagation of interfered hydraulic fractures by alternated radial-circumferential extensions and its impact on proppant distribution

The fracture extension mechanisms and proppant transport characteristics play key roles for optimizing hydraulic fracturing in unconventional reservoirs. In this work, the visual physical simulation method was used to analyze the 3D dynamic extension processes of multi-stage hydraulic fractures and the subsequent impact on proppant distribution. The interfered fracture in multi-stage hydraulic fracturing exhibit alternated radial-circumferential extension behavior. More specifically, these behavior changes from unilaterally radial initiation, circumferential extension to radial extension. Unilaterally radial initiation results in the formation of both mirror and conchoidal features, while circumferential extension leads to stepped feature, and radial extension gives rise to feather feature. The four features of hydraulic fractures result in four types of non-uniform proppant distribution: uniform, scattered, cluster, and regional distribution. The proppant transport shifted from linear to radial mode, promoting further fracture extension. The effects of segment spacing and proppant injection sequence were studied. The results showed that the influence on the interfered fracture decreases as the segment spacing increases. In addition, the propped fracture area is larger when the small-size proppant is injected first, followed by large-size one. The research can improve understanding and optimization of multi-stage hydraulic fracturing in unconventional oil and gas reservoirs.

Shale brittleness evaluation under high temperature and high confining stress based on energy evolution

Deep and ultra-deep shale gas reservoirs are crucial targets for future natural gas development. Extensive research has shown the shale brittleness is closely associated with the hydraulic fracture network quality. However, the shale brittleness may be altered in deep reservoirs due to the high temperature and high geo-stress. At present, commonly used shale brittleness evaluation methods cannot distinguish the differences in energy evolution caused by different mineral components in shale rock. In order to distinguish this difference, this study innovatively proposes a shale brittleness evaluation method that considers mineral composition based on energy evolution. A high-temperature triaxial compression experiment was carried out on the Longmaxi Formation shale, its fracture mode was analyzed, and the brittleness of the shale was evaluated based on this innovative method. The results indicate that with increasing confining stress, the shale fracture mode transitions from brittle tensile-shear multi-crack penetrating fracture to brittle-plastic shear single-crack fracture, and the brittleness of shale shows a decreasing trend. Under low confining stress, the shale brittleness decreases with temperature. Under high confining stress, temperature is the non-main controlling factor of shale brittleness. This study provides valuable guidance for the design and optimization of hydraulic fracturing in deep shale reservoirs.

Analytical Optimization of Hydraulic Fracturing

Hydraulic fracturing optimization is a critical aspect of improving the recovery of unconventional shale formation. This paper discusses the use of different types of proppants, rate optimization, and proppant amount optimization to improve hydraulic fracturing techniques. The paper begins with a discussion of proppant selection, which is a critical aspect of hydraulic fracturing. The authors highlight the importance of proppant endurance in holding the fracture opening and provide a range of proppants suitable for different confining pressures. Tables and charts are included to illustrate the permeability values of various proppants under different closure stress values. This section also emphasizes the significance of proppant shape in creating a more conductive path in the fracture. The next section of the paper discusses the methodology used in the study, including the Fracpro software simulation parameters. The authors then delve into the optimization of proppant specific gravity and the results of their experiments with five different types of proppants. The paper highlights the impact of proppant specific gravity on fracture width and dimensionless conductivity (FCD). The author also focusses on the optimization of pumping rate, which is an essential parameter of hydraulic fracturing operations. The paper includes simulation studies conducted to determine the effects of pumping rate on fracture parameters such as propped length and propped height. The authors highlight the relationship between rate and FCD and how it is affected by permeability values of the proppant. Finally, the paper discusses proppant amount optimization, which is a critical point of hydraulic fracturing optimization. The authors provide an overview of the results of the experiments conducted to determine the optimal amount of proppant required for different hydraulic fracturing operations. Overall, this paper provides valuable insights for researchers and engineers working to improve hydraulic fracturing techniques for tight shales formation. The authors use a combination of theory, experiments, and charts to provide a comprehensive overview of the various aspects of hydraulic fracturing optimization.

Preconditioning optimization of hydraulic fracturing in block caving of hard rock mass

Introduction: Cavability issues often arise in hard rock mines employing the block caving mining method. Hydraulic fracturing stands out as a promising pre-conditioning technology for hard rock masses, with its pre-conditioning effects dependent on variable parameters.Methods: The impact of cluster number, injection rate, and liquid volume on fracture propagation was investigated through on-site hydraulic fracturing practices. Fracturability was initially verified via true triaxial fracturing tests, and preconditioning parameters were subsequently optimized using numerical simulations. The optimized on-site construction was monitored using electromagnetic methods.Results: The study revealed a negative correlation between fracture radius and the number of clusters, gradually decreasing with an increase in cluster number. However, the fracture weakening area increased with the rise in the number of clusters. The fracture weakening area also increased with the injection rate. Additionally, the fracture radius initially increased and then decreased. Both fracture weakening area and radius increased with an increase in liquid volume. The optimized parameters were identified as four clusters, an injection rate of 4 m3/min, and a liquid volume of 500 m3.Discussion: Building upon these findings, on-site experiments were conducted and monitored using electromagnetic methods. The monitored results demonstrated that the optimized parameters effectively achieved hydraulic fracturing expansion, accomplishing the goal of weakening hard rock.

Application of AFM on Identifying Mechanical Properties of Individual Minerals and Surface Properties of Crack with High Resolution in Shale

Improving the resolution and accuracy of the mechanical properties of organic-rich shale is very important. The results can reveal the mechanical properties of shale from micro scale and serve as a guide for the design of hydraulic fracture optimization parameters. This study introduced an advanced technique to obtain the mechanical properties of shale with high resolution (58.6 nm/pixel) by combining SEM, EDS, and Atomic Force Microscopy (AFM). To locate the target area in SEM and AFM accurately, a positioning technique that uses special distributions of pyrite was established. AFM PeakForce QNM mode was selected due to its advantages at capturing topography and mechanical properties in material. Results illustrated the ability of AFM to obtain the mechanical properties (modulus) of individual mineral components in shale, the detailed topography of crack, and mechanical properties of minerals in a specific area. In particular, the mechanical properties of minerals around crack explained the layered distribution of minerals around the fractures, and the cracks developed in the clay mineral layer was detected. This article demonstrates the great potential application of AFM in shale.

Effect of fracture behavior variables on hydraulic fracturing optimization by adding graphene nanosheets to sand/water mixtures: A molecular dynamics approach

Hydraulic fracture is one of the promising techniques for the breakage of rock without blasting, thus the investigation of its internal mechanism is helpful to develop forecasting system for ground pressure. In this study, molecular dynamics (MD) method was used to describe the effect of graphene nanosheets (GNS) (with different edges) on the hydraulic fracturing process. More specifically, in the MD box, we simulated the effects of GNS on rock substrates, the mixtures of H2O and sand, and sands that deviate from the specified atomic substrates. Therefore, we calculated the parameters, such as temperature, total energy and mutual forces of atomic structures. In these simulations, mixture fluid is simulated by sand particles and water molecules with the Universal Force Field (UFF). Physically, adding GNS to mixture fluid caused a decrease in the number of trapped sand particles in the fracture of rock matrix. The sand particles removed from rock matrix fracture. This atomic phenomenon optimized the hydraulic fracturing process and reduced operating costs. Numerically, in our simulations, the atomic structures’ temperature and potential energy converged to 300 K, and −479 eV (respectively). Furthermore, trapped sand particles in MD simulations decreased to 14 particles using GNS. Our results show that the trapped sand particles reached their minimum rate (14 particles) by 2.5% atomic ratio of GNS inserting into the initial atomic mixture fluid. This atomic behavior results from the energy of the interactions between sand particles, and rock substrate. The interaction energy between the sand particles and the substrate reduced to a –32.38 eV by adding GNS to original H2O-sand mixture. This atomic evolution caused the volume of trapped sand particles reached to minimum value in the presence of GNS with optimum atomic ratio.

Study on the Fracture Propagation in Multi-Horizontal Well Hydraulic Fracturing

Multi-horizontal well hydraulic fracturing is a widely employed and highly effective method for stimulating tight and shale reservoirs. However, most existing studies primarily focus on investigating the impact of intra-well interference on fracture propagation while neglecting the influence of inter-well interference. Here, a multi-well hydraulic-fracture-propagation model is established to examine the effects of inter-well interference on fracture propagation within a multi-well system. In this study, based on the bilinear T-S criterion, the stiffness degradation is used to describe the damage and evolution process of fracture, the coupling process of fluid flow and solid damage and deformation is realized, and the dynamic distribution of inter-fracture flow is realized by using Kirchhoff function on the basis of the cohesive zone method (CZM) finite element model. Finally, the fracture-propagation model of multiple horizontal wells is established. Based on this model, the mechanism of inter-well interference on fracture propagation is studied, and the influence law of Young’s modulus and fracture displacement on fracture propagation in multi-wells is investigated. The results show that the reservoir can be divided into self-influence area, tension area and compression area according to the stress distribution state in the hydraulic fracture propagation of multi-wells. The propagation rate of hydraulic fractures in horizontal wells is significantly accelerated when they propagate to the local tension area generated by the fracture tip of neighboring wells, and rapidly decreases as the hydraulic fractures continue to propagate to the compression area of neighboring wells. Rocks with a lower Young’s modulus tend to be more plastic, forming hydraulic fractures with usually lower fracture lengths and usually larger fracture widths. The hydraulic fracture has an inhibitory effect on the propagation of fractures closer to each other in neighboring wells, and this inhibitory effect gradually increases as the distance decreases. The dominance of the dominant fracture to propagate in the self-influence area gradually decreases under inter-well and intra-well interference. As the dominant fracture propagates into the tension and compression areas of the neighboring well fractures, the feed fluid will show a brief rise and then eventually stabilize. This study quantifies the effect of inter-well interference on fracture propagation and lays the foundation for treatment optimization of small well spacing hydraulic fracturing.

Numerical simulation on hydraulic fracture propagation in laminated shale based on thermo-hydro-mechanical-damage coupling model

The temperature of a deep shale reservoir may reach more than 100°C, and the effect of thermal shock on shale hydraulic fracturing has rarely not been considered in previous studies. Based on mesoscopic damage mechanics and the finite element method, a thermo-hydro-mechanical-damage (THMD) coupling model considering temperature, seepage, stress, and damage fields was constructed to investigate the effects of reservoir temperature, convective heat transfer coefficient ( h), in-situ stress difference and bedding plane angle ( αθ) on shale hydraulic fracturing. The results show that multiple hydraulic fractures (HFs) can occur under thermal shock and that HFs control the distribution of seepage, temperature, and stress fields. Reservoir temperature, in-situ stress difference and αθ are primary factors affecting hydraulic fracturing, whereas h is a secondary factor. When the reservoir temperature rises from 50°C to 150°C, the initiation and breakdown pressures decrease by 65.5% and 16.7%, respectively. HFs cross the bedding plane more easily, and fracture complexity is obviously enhanced. A higher h is favourable for slightly reducing the initiation and breakdown pressures, but it has little influence on the fracture complexity. Once the in-situ stress difference is low, there is a high fracture complexity, but HFs are more easily captured by bedding planes to limit the propagation of fracture height. When the in-situ stress difference is high, HFs are more likely to form bi-wing fractures. Whether αθ is too large or small, it is not conducive to improving the fracture complexity. In this study, when αθ is 30°, HFs and bedding planes intersect to form a fracture network. Essentially, thermal shock plays a key role in reducing the initiation pressure and forming multiple HFs during the fracturing process, and fracture propagation mainly depends on the injection pressure. The results can serve as reasonable suggestions for the optimization of shale hydraulic fracturing.

The prediction and optimization of Hydraulic fracturing by integrating the numerical simulation and the machine learning methods

Hydraulic fracturing (HF) is an indispensable technique to economically develop unconventional oil/gas resources. More careful design and optimization of the field HF treatment can lead to a more satisfactory profit. Due to the uncertainty and complexity of the petroleum domain problems, the application of the machine learning (ML) method in such fields encountered many drawbacks in previous attempts. This paper proposed a new method, embodying the physical information, to find the most profitable completion design with high effectiveness and efficiency. The proposed model can accurately represent the Non-linear relationship between inputs and outputs. Meanwhile, incorporating the prior knowledge can enhance the generalization ability of the proxy model. The proposed model has been verified by two application scenarios. For both, the fracture propagation code and automated reservoir simulation code are integrated to generate the datasets. The input vector contains the treatment pressure of each stage, the treatment volume of each stage, and the cluster spacing. The output is the corresponding Net Present Value (NPV). Five proxy models are generated based on the proposed model, the regular neural network (NN), the Random Forest (RF), the Adaptive Boosting (AdaBoost), and the support vector machines (SVM) algorithms. By comparison, the prediction accuracy of the proposed model is superior to other models. The scaled Mean Squared Error (sMSE) of the predicted model increased by 16%, 346%, 266%, and 133%, respectively. Meanwhile, the proposed model has shown a higher generalization ability. The Relative Absolute Error (RAE) of the proposed model remains the lowest and the difference from other models becomes larger with the increase of the noise amounts. By introducing prior knowledge, the proposed model can predict the NPV more accurately and robustly.

Fracture-initiation pressure model of inclined wells in transversely isotropic formation with anisotropic tensile strength

Fracture-initiation pressure (FIP) is closely related to lost circulation and hydraulic fracturing. However, conventional prediction models often treat formation rock as an isotropic medium, ignoring the anisotropy of rock materials, particularly, the anisotropy of tensile strength. Therefore, a universal FIP model was proposed for inclined well in transversely isotropic formations, and the combined effects of both anisotropic elasticity and tensile strength were taken into account. The proposed model was verified by indoor experiments, and the predicted FIPs of isotropic and anisotropic models were compared. Finally, the influencing factors of FIP were investigated. The results indicated that compared with the experimental results, the present model is more consistent than traditional models, and the deviation factor is concentrated between 0.8 and 1.4. Compared with the traditional isotropic model, the maximum differences of the elastic anisotropic model, strength anisotropic model, and the present model are 0.059 g/cm3, 0.262 g/cm3, 0.258 g/cm3, respectively. The dip direction has almost no effect on the FIP at a low dip angle, while it has a significant effect at a high dip angle. The FIP is the minimum when the dip direction is parallel to the azimuth of wellbore, while it is the maximum when the dip direction is perpendicular to the azimuth of wellbore. With the increase of anisotropy index, the influence of elastic anisotropy and strength anisotropy is enhanced, and the maximum difference is 0.31 g/cm3 and 0.33 g/cm3 respectively; while the Poisson's ratio only has a small effect, and the maximum difference is only 0.256 g/cm3. The spatial distribution parameter (Ω0) directly affects the variation trend of tensile strength, too high a Ω0 may overestimate the FIP, while too low a Ω0 may underestimate the FIP. The present model and analysis results can provide theoretical guidance for lost circulation prevention and hydraulic fracturing optimization.

The influence of acidizing on propped fractures for productivity enhancement: Eagle Ford laboratory study

Hydraulic fracturing of tight formations and placing proppants within induced fractures are commonly performed in unconventional shale reservoirs all over the world, especially in North America. However, the overall recovery of these oil and gas resources is very low and hence, production enhancement is inevitable.This study investigated the acidizing of propped fractures as a recovery enhancement method in Eagle Ford shale samples. Experiments were designed using sample slabs having proppants between them. Differing parameters were examined to optimize the fracture conductivity through acidizing. For a range of confining pressures, the fracture conductivity was maximized by minimizing the proppant embedment. A higher acid injection rate was achieved with a 5 % HCl concentration. Proppant concentration and proppant size were found to affect fracture conductivity inversely. However, this trend was not observed to be monotonic. In terms of production parameters, the skin factor determined the optimized conditions at a constant confining pressure. Overall, the optimum conditions for acidizing in the propped fractures were determined while having 5 % HCl concentration, 1 lb/ft2 (4.88 kg/m2) proppant concentration, 600–710 μm of proppant size and 8 ml/min acid injection rate. These findings confirmed the applicability of the method for hydraulic fracturing optimization in Eagle Ford shale samples. It can also be regarded as a primary enhancement method due to its low cost and the process simplicity in comparison to hydraulic fracturing operations. The experimental results of this study would correspondingly enlighten their potential field applications through facilitating appropriate modification with regards to specific operational conditions.

Research Advance on Prediction and Optimization for Fracture Propagation in Stimulated Unconventional Reservoirs

Abstract Multistage stimulation horizontal wells are prerequisite technologies for efficient development of unconventional reservoir. However, the induced fracture network morphology from hydraulic fracturing is very complex and affected by many factors, such as the in situ stress, rock mechanical properties, and natural fracture distribution. The large numbers of natural fractures and strong reservoir heterogeneity in unconventional reservoirs result in enhanced complexity of induced fractures from hydraulic fracturing. Accurate description of fracture network morphology and the flow capacity in different fractures form an important basis for production forecasting, evaluation (or optimization) of stimulation design, and development plan optimization. This paper focuses on hydraulic fracturing in unconventional reservoirs and discusses the current research advances from four aspects: (1) the prediction of induced fracture propagation, (2) the simulation of fluid flow in complex fracture networks, (3) the inversion of fracture parameter (fracture porosity, fracture permeability, etc.), and (4) the optimization of hydraulic fracturing in unconventional reservoirs. In addition, this paper provides comparative analysis of the characteristics and shortcomings of the current research by outlining the key technical problems in the study of flow characterization, parameter inversion, and optimization methods for stimulation in unconventional reservoirs. This work can provide a certain guiding role for further research.

Technology Focus: Hydraulic Fracturing Operations (June 2022)

The recovering global economy, post the pandemic and current geopolitical circumstances, has underscored the reliance on energy to drive global development. Underinvestment in oil and gas projects over the past few years, coupled with a sudden increase in energy demand, has put the onus on oil and gas companies to accelerate the ramp-up of deferred projects. As winter approaches every year, global gas consumption increases exponentially. Because gas is a cleaner source of energy, countries and organizations once solely focused on oil exploration have shifted their strategies to concurrently explore for gas reserves. As a means of meeting the current increase in energy requirements, there is a push around the world to replicate the North American shale-development strategy of long horizontals with multiple hydraulically fractured stages targeting these oil and gas reserves. Low oil and gas prices in the recent past have necessitated a focus on the wider implementation of efficient fracturing technologies, in terms of both operations and production, with the aim of maximizing returns with minimal investment. There has been greater emphasis on moving away from the factory approach and using a more-engineered well-by-well approach. The past decade has seen many technological innovations in the well-completion domain focused on hydraulic fracturing. Within openhole multistage completions, we have seen a wider use of higher-expansion-ratio packers, such as metal expandable packers; fracturing-sleeve configurations, which enable greater stage count in a single well than previously possible; multicluster fracturing sleeves; dissolvable ball and seat technologies; and reclosable sleeves, to name a few. On the other end of the spectrum, when we look at cased-hole completions, we have seen great improvements in pumpdown technologies, dissolvable plugs, and advanced perforation and logging technologies, among other developments. There have also been great advances in fracture propagation and stage-contribution monitoring, moving from traditional radioactive tracers to various nonradioactive tracers, and developments in microseismic and fiber-optic monitoring as well as production-logging technologies. In an environment where we are limited by both surface facilities and subsurface well placement, these technologies have been crucial in trying to better understand the interaction between parent and child wells along with formulating field strategies in new basins. The implementation of machine learning and artificial intelligence in the fracture design and analysis domain, as well as in fracturing equipment operation and maintenance, has led to further optimization in planning and resource management. Some of these technologies can indirectly help us lower the carbon footprint while fracturing. As an industry, we are at a critical point where, along with advancements in hydraulic fracturing optimization, it is important to focus on highlighting our technological achievements and developments through the mainstream media. It is critical to emphasize the efforts of the oil and gas industry in lowering the environmental impact of hydraulic fracturing by using minimal resources and maximizing energy generation to fuel global economic growth. Considering the renewed focus on hydraulic fracturing as a means of meeting the world’s energy requirements, we can expect to see considerable advancement and introduction of new innovative technologies in the near future. Recommended additional reading at OnePetro: www.onepetro.org. SPE 200846 - Novel Application To Recognize a Breakdown Pressure Event on Time Series Fracture Data vs. an Artificial-Intelligence Approach by Alberto Jose Ramirez, Well Data Labs, et al. SPE 201376 - Pumpdown Diagnostics for Plug-and-Perf Treatments by David Cramer, ConocoPhillips, et al. SPE 203284 - Critical Review of Multistage Fracturing Completions and Stimulation Methods by Eyad A. Alali, Saudi Aramco, et al.

Analytical model for fracture conductivity with multiple particle sizes and creep deformation

The prediction of fracture conductivity in shale reservoirs is necessary for hydraulic fracturing optimization. However, problems remain with the prediction of fracture conductivity in shale reservoirs. Shale exhibits creep deformation behavior. In addition, due to the combination of large and small particle sizes, proppant, and discontinuous distribution fractures, it is challenging to establish an embedment and fracture conductivity model that combines the creep factor and multiple particle sizes.Based on the authors’ previous work, the modified Burgers creep model was introduced into the discontinuous embedment model for multiple particle sizes, and then combined with the KC equation for multiple particle sizes to develop an embedment depth and conductivity prediction model under the conditions of creep and discontinuous distribution of multiple-particle-size proppants.The results showed that the creep time increased from 10 d to 100 d, and the critical closure pressure of the minimum particle size proppant embedded in the rock decreased from 36 MPa to 14 MPa. The closure pressure increased from 20 MPa to 40 MPa, and the critical creep time of the minimum particle size proppant embedded in the rock decreased from 30 d to 12 d. Under the condition of two-particle-size proppant combinations, there is a proppant combination ratio that minimizes the fracture conductivity, which was approximately 0.2 in this study. The longer the creep time, the greater the optimal proppant distance coefficient. The greater the viscosity of the rock and proppant, the smaller the optimal proppant distance coefficient. These research results provide a theoretical basis for optimizing the local conductivity of secondary fractures in shale reservoirs.

Surrogate-assisted hydraulic fracture optimization workflow with applications for shale gas reservoir development: a comparative study of machine learning models

Unconventional reservoirs have become the main alternative for increasing oil and gas reserves around the world. Owing to their ultralow permeability properties and special pore structure, hydraulic fracturing technology is necessary to realize the efficient development and economic management of unconventional resources. To maximize the production capacity of wells, several fracture parameters, including fracture number, length, width, conductivity, and spacing, need to be optimized effectively. The optimization of hydraulic fracture parameters in shale gas reservoirs generally demands intensive computations owing to the necessity of numerous physicalmodel simulations. This study proposes a machine learning (ML)–assisted global optimization framework to rapidly obtain optimal fracture parameters. We employed three supervised ML models, including the radialbasis function, K-nearest neighbor, and multilayer perceptron, to emulate the relationship between fracture parameters and shale gas productivity for multistage fractured horizontal wells. Firstly, several forward shale gas simulations with embedded discrete fracture models generate training samples. Then, the samples are divided into training and testing samples to train these ML models and optimize network hyper parameters, respectively. Finally, the trained ML models are combined with an intelligent differential evolution algorithm to optimize the fracture parameters. This novel method has been applied to a naturally fractured reservoir model based on the real-field Barnett shale formation. The obtained results are compared with those of conventional optimizations with high-fidelity models. The results confirm the superiority of the proposed method owing to its very low computational cost. The use of ML modeling technology and an intelligent optimization algorithm could greatly contribute to simulation optimization and design, prompting progress in the intelligent development of unconventional oil and gas reservoirs in China.

Characterization and Mechanical Property Measurements by Instrumented Indentation Testing of Niger Delta Oil Shale Cuttings

Oil shales have unstable mechanical and chemical properties, which makes their extraction for characterization and conventional mechanical testing uneasy and complex. Most often, mechanical property measurements are usually taken from core samples that are costly to extract and test using conventional testing methods. This paper presents a focused study carried out on oil shale cuttings obtained from the sidewalls of two different wellbore depths in the Niger Delta area of Nigeria. Using the X-ray Diffraction (XRD) and Scanning Electron Microscope (SEM) characterization techniques, the morphology of these shales was studied. The results obtained clearly showed the composition, bonding and variations in the morphology of the studied shale samples. Furthermore, the heterogeneity associated with these shales across varied depths were revealed. An efficient and less expensive technique compared to conventional testing methods, instrumented indentation testing (IIT) was carried out to obtain essential mechanical parameters of the shale specimen. These properties are important parameters in determining the hydrocarbon storage space of shale formations, wellbore stability, and optimization of hydraulic fracturing which is necessary for efficient drilling operations.

Fracturing Optimization Design of Fractured Volcanic Rock in Songliao Basin Based on Numerical Research and Orthogonal Test

Abstract The efficient development of fractured volcanic reservoir relies on fracturing, while the existence of natural fractures has an important impact on hydraulic fracturing in this reservoir. There are few reports on fracturing optimization of deep volcanic gas reservoirs in Songliao Basin in China; thus, the parameter optimization under single-stage action is studied. On the basis of logging interpretation, coring observation, and seismic interpretation, the fracture development degree is obtained. By employing numerical simulation and orthogonal tests, hydraulic fracturing optimization design is carried out. The results indicate that the pumping rate of 0.01 m3/s/m and perforation direction parallel to the maximum principal stress are the optimum parameters for the studied volcanic reservoirs. In addition, multibranch seam expansion will occur when the displacement reaches 0.01 m3/s/m according to fracture morphology results after fracturing. And the research method has certain significance for improving the fracturing design of fractured reservoir in the research block.

Production Improvement via Optimization of Hydraulic Acid Fracturing Design Parameters in a Tight Carbonate Reservoir

Hydraulic fracturing can be utilized to extract trapped hydrocarbon where integrated fracture networks do not exist for sufficient production. In this work, design parameters of a hydraulic acid fracturing of a tight carbonate reservoir in the Middle East were optimized. The effect of optimized hydraulic fracturing on production performance and rate was investigated. Using the petrophysical well logs, formation integrity tests, core data the Mechanical Earth Model (MEM) of the tight carbonate reservoir was created, which resulted in rock mechanical properties and in-situ stresses. The other required parameters for fracturing design were either measured or found from empirical correlations. Following a candidate selection of suitable layers for fracturing, the input parameters were loaded in GOHFER software to design and optimize the fracturing job. Finally, the production forecast was performed and compared with current conditions. The injection parameters (flow rate, total volume, and number of stages) of the fracturing fluid (composed of guar and CMHPG and polymer with 15% HCL acid) were optimized to reach optimum resultant fracture geometry. Finally, optimized injection parameters were found at the injection flow rate of 18 barrels per minute, total injection volume of 90 K-gal, and three stages of injection. Using the optimal injection parameters, the optimized fracture geometrical sizes were determined: the fracture half-length (Lf): 148 m (486 ft), fracture height (Hf) of 64 m (210 ft) and fracture width (Wf) of 0.0962 in. Finally, the effect of this stimulation method on future production performance was investigated. The well production rate showed an increase from 840 STB/Day (before fracturing) to 1270 STB/Day (post fracturing). This study contributes to the practical design and optimization of hydraulic fracturing in the tight carbonate formation of the investigated oilfield and the other potential fields in the region. The results showed that this stimulation method can efficiently improve production performance from reservoir formation.

Simulation and optimization of hydraulic fracturing in shale reservoirs: A case study in the Permian Lucaogou formation, China

Long horizontal sections, small well spacings, and dense cutting are the main methods for shale reservoir development. However, there are still significant differences in oil production after large-scale fracturing of horizontal wells due to reservoir heterogeneity. This study presents a fracturing design method based on sweet spot mapping to determine the adaptability of reservoir quality and fracturing scale in order to improve the fracturing effect. First, geomechanics model is constructed utilizing logs and core laboratory tests. Then, comprehensive sweet spot mapping is captured through the two-level fuzzy comprehensive evaluation method, which considered the reservoir physical quality and engineering quality. The sweet spot divides the reservoir into three types: type I (good), type II (moderate), and type III (poor). Finally, fracturing simulation and reservoir numerical simulation are performed to optimize the fracturing parameters for different types of sweet spots. Results show that there is a strong correlation between type I sweet spot and productivity. Increasing drilling rate for type I sweet spot can improve productivity. The 5-year cumulative oil production of segmented way based on sweet spot types is 4005 m3 higher than that of uniform segmented way. Reasonable stage lengths of type I, II, and III sweet spot are 66.67 m, 50 m and 40 m, respectively, and cluster spacing is between 10 m and 12 m. Reasonable single-stage fracturing fluid volume for type I and type II sweet spot is 2200 m3, and type III is 1900 m3. Specifically, the results of applying the optimized parameters to actual well demonstrate that the design scheme has a 5-year cumulative oil production of 7026 m3 and NPV of $1.01 million higher than the actual scheme. This method will be helpful for engineers in developing a reasonable fracturing plan for shale oil in future operations.

Optimization of hydraulic fracturing with rod-shaped proppants for improved recovery in tight gas reservoirs

Due to the increasing demand and importance of natural gas in the global energy mix, its expeditious recovery is crucial, especially from large-scale unconventional geo-resources. Hydraulic stimulation is an established means of productivity increase especially from tight gas reservoirs. The fracture conductivity generally depends on proppant properties, particularly the shape. Therefore, in this research, the effect of using rod-shaped proppants was investigated. Using rod-shaped proppants instead of conventional spherically shaped proppants, can make a significant difference. Due to the cylindrical shape, higher porosity and permeability are generated, resulting in better conductivity fractures. Thus, to analyze the effect of different proppant shapes on post-fracture performance, a production model was implemented in the FLAC3Dplus-TMVOC framework. Later, an in-depth sensitivity analysis was performed to investigate the effects of the proppant shape, size, strength, and effective stress on the fracture aperture reduction and conductivity due to proppant deformation and embedment. The application to a generic model revealed that recovery can be increased by about 7% using aspect ratio 1 rod-shaped proppant with the same diameter as the spherical proppant. Then, increasing the rod-shaped proppant size from an aspect ratio of 1–10 can significantly increase the gas recovery by 13% but results in higher proppant deformation. Finally, the application of rod-shaped proppants to fracturing proposals in well x in a tight gas reservoir of Germany showed that the recovery could be significantly improved if spherical proppants are replaced with rod-shaped proppants.