Simulation Of Hydraulic Fracturing Research Articles

Influences of clean fracturing fluid viscosity and horizontal in-situ stress difference on hydraulic fracture propagation and morphology in coal seam

The viscosity of fracturing fluid and in-situ stress difference are the two important factors that affect the hydraulic fracturing pressure and propagation morphology. In this study, raw coal was used to prepare coal samples for experiments, and clean fracturing fluid samples were prepared using CTAB surfactant. A series of hydraulic fracturing tests were conducted with an in-house developed triaxial hydraulic fracturing simulator and the fracturing process was monitored with an acoustic emission instrument to analyze the influences of fracturing fluid viscosity and horizontal in-situ stress difference on coal fracture propagation. The results show that the number of branched fractures decreased, the fracture pattern became simpler, the fractures width increased obviously, and the distribution of AE event points was concentrated with the increase of the fracturing fluid viscosity or the horizontal in-situ stress difference. The acoustic emission energy decreases with the increase of fracturing fluid viscosity and increases with the increase of horizontal in situ stress difference. The low viscosity clean fracturing fluid has strong elasticity and is easy to be compressed into the tip of fractures, resulting in complex fractures. The high viscosity clean fracturing fluids are the opposite. Our experimental results provide a reference and scientific basis for the design and optimization of field hydraulic fracturing parameters.

Modeling of Fiber Optic Strain Responses to Shear Deformation of Fractures

Identifying distributed strain sensing (DSS) patterns (or signatures), particularly those arising from different hydraulic fracture geometries, has gained significant attention and research effort. Recent works have generated a catalogue of signatures for planar hydraulic fractures in an elastic rock formation. Yet, in numerous cases (e.g., fault motion and some geothermal reservoir stimulation), the main mode of deformation is a shear on a fracture or a network of natural fractures (particularly during low pressure injection/circulation). However, the specific fiber signatures that result from such shear deformation have not been studied. In this study, we use a three-dimensional poroelastic hydraulic fracture simulator to capture the strain signatures resulting from the shear deformation of fractures in various orientations with respect to the monitoring well. Five key cases are examined: one where the fracture strike is perpendicular to the fiber, another with the strike running parallel to the fiber, a third case where the fracture strike is at 45 degrees to the fiber, a fourth case with a strike slip fault perpendicular to the fiber, and a fifth case where fiber is intersecting the fracture. Theoretically and physically meaningful results were obtained in all five cases, which completely differ from the heart-shaped signature of tensile fracture propagation. It was discovered that the strain pattern changes with the shear deformation direction with respect to the fiber. The model is then used to simulate the response of a fracture network at Utah FORGE to injection to assess whether a signature might be expected in response to the planned injection and circulation rates, and, if so, what strain pattern might be expected. The simulation confirms that a strain response can indeed be observed. More importantly, the fiber response that would be detected in the monitoring well would be a combination of strain signatures from dilation and shear deformation of differently oriented natural fractures. The results in this study provide useful insights on the application of fiber to other stimulation and/or circulation scenarios where shear deformation of a fracture or fracture network plays a major role.

Hydraulic fracturing simulation of concrete dam integrating intelligent crack detection and refined modeling methods

Concrete dams are prone to cracks during construction and operation process. Cracks on the upstream surface may induce the risk of hydraulic fracturing, thereby significantly reducing the safety of dam structure. Nevertheless, image processing technology, non-destructive testing technology and structural performance analysis technology with cracks are in a relatively independent state, leading to difficulties in analysis of actual cracks combined with numerical simulations. This paper proposes a novel approach for combination of intelligent identification technology and refined finite element method (FEM) for modeling and simulating the hydraulic fracturing resistance of the actual crack in concrete dams. With image processing technology and non-destructive testing technology, direction and depth of actual cracks are identified and extracted, then the 3D geometric model of actual cracks is generated. The refined model with the identified actual crack is constructed by the node projection strategy. This approach is used to assess the hydraulic fracturing resistance of the concrete dam with actual cracks in the alpine region. The results demonstrate that the critical crack depth of hydraulic fracturing is 12.93 m, and the opening width is 1.01 mm, which is 2.53 times the limit value for Class D cracks in the code (DL/T5251–2010). The refined modelling method based on actual crack detected on site can accurately evaluate the crack state compared to the conservative code.

Injection Temperature Impacts on Reservoir Response during CO2 Storage

Summary Sustained injection of industrial-scale volumes of cold CO2 into warmer subsurface rock will result in extensive cooling which can alter rock mass mechanical behavior and fluid migration characteristics. Advanced simulation tools are available to assess and characterize such phenomena; however, the effective use of these tools requires appropriate injection temperatures and rock thermophysical parameters (in addition to geomechanical and hydraulic properties). The primary objective of this study was to demonstrate the sensitivity of injection-induced tensile fracturing and fault reactivation to injection temperature and reservoir thermophysical properties during CO2 injection operations. This was achieved by (1) compiling and reviewing thermophysical parameter data available for formations in the province of Alberta, Canada, and CO2 injection temperature records for CO2 injection projects in western Canada and (2) using a 3D, physics-based, fully integrated hydraulic fracturing and reservoir simulation numerical model to examine the geomechanical response of several potential CO2 reservoirs in the Alberta Basin as a function of injection temperature, thermal conductivity (TC), and coefficient of linear thermal expansion (CLTE) values. The simulation results indicate that reducing the fluid injection temperature from 15°C (assumed in previous work) to 2°C (conservative value selected based on temperature data reviewed in this work) could trigger extensive vertical (20–130 m high, 100–600 m long) tensile fractures with rapid fracture initiation and full vertical growth within short periods (weeks to months) and continued horizontal length increase. When low values for thermophysical properties are used, the results show that thermally-induced tensile fracturing is unlikely, whereas the use of high values results in extensive tensile fracturing in all simulations. A similar conclusion was reached for the thermally-induced reactivation (unclamping) of proximal, critically-stressed faults. Notably, slip is predicted for all simulations where high thermophysical property values are used. This confirms that accurate determination of minimum fluid injection temperature and thermophysical parameters is important for containment risk assessment for commercial-scale CO2 storage projects. Another significant outcome of this work is the observation that most thermophysical parameters in the available data were measured using experimental conditions and/or temperature paths that are not representative of CO2 injection projects. As such, the development and validation of best practice approaches for accurate assessment of these parameters seem necessary.

A New Symmetry-Enhanced Simulation Approach Considering Poromechanical Effects and Its Application in the Hydraulic Fracturing of a Carbonate Reservoir

The exploration of fractured-vuggy carbonate reservoirs usually involves hydraulic fracturing to maximize recovery. At present, effectively communicating natural discontinuities is a technical challenge. In this article, we investigated the origin and propagation of cracks in fractured-vuggy reservoirs using discrete element hydraulic fracturing simulations that included poromechanical effects. A particular focus on the microscopic force-displacement symmetry of adjacent pore pressures is introduced. Our results demonstrate that the poromechanical effect significantly increases the strength of overpressurized reservoir formations. Moreover, the effect of injected fluid viscosity on the hydraulic fracturing effectiveness was studied through two simulation tests. The outcomes highlight the critical influence of fluid viscosity on the propagation of micro-cracks in overpressure fractured-vuggy reservoirs.

Multi-stage hydraulic fracturing simulation methodology at the wells of the gas condensate field X

The purpose of this work is to select the optimal method for multi-stage hydraulic fracturing simulation at the wells of a large gas condensate field X in conditions of low-permeability reservoirs and potential risk of condensate loss in the near bottomhole zone with a decrease in reservoir pressure. At the moment, there are many ways to simulate hydraulic fracturing, each of which is characterized by its advantages and disadvantages. For specific simulation conditions, it is necessary to choose the most optimal method of hydraulic fracturing simulation, which allows you to correctly simulate all the effects that are expected during development. Within the framework of the current work, the most common numerical methods of hydraulic fracturing simulation were described in abstract, their advantages and disadvantages for specific conditions of field X were reflected. Special attention was paid to the comparison of hydraulic fracturing simulation techniques using virtual perforations and local grid refinement, since these techniques are the most common ways to set hydraulic fracturing in existing hydrodynamic simulators. Scenario calculations were carried out, which made it possible to determine the limits of applicability of various methods, compare the correctness of reproducing downhole effects, quantify the deviation of the calculation results of different methods from the reference calculation. In addition, in the course of the work, various features of the application of the hydraulic fracturing simulation through local grid refinement were described, which were revealed experimentally. As a result, for multi-stage hydraulic fracturing simulation was used a method in which the cells with hydraulic fracturing are logarithmically chopped relative to the original grid. This method allows to simulate the actual rate of decline in well productivity in conditions of low reservoir permeability, and also allows to simulate in the hydrodynamic model the effect of condensate precipitation in the near bottomhole zone and the subsequent decrease in gas productivity.

Numerical Simulation of Hydraulic Fractures Breaking through Barriers in Shale Gas Reservoir in Well YS108-H3 in the Zhaotong Shale Gas Demonstration Area

Estimating the effectiveness of hydraulic fracturing in the context of the incrfease in the shale gas demand is of great significance for enhancing shale gas production, which aims to substantially reduce fossil energy consumption and CO2 emissions. The Zhaotong national shale gas demonstration zone has complex stress structures and well-developed fracture zones, and thus it is challenging to achieve targeted reservoir segment transformation. In this paper, we construct and optimize the geometry of hydraulic fractures at different pressures considering the upper and lower barriers in hydraulic fracturing simulation experiments and numerical modeling. The numerical simulation results show that the pore pressure exhibits a stepped pattern around the fracture and an elliptical pattern near the fracture tip. During the first time of injection, the pore pressure rapidly increases to 76 MPa, dropping sharply afterward, indicating that the fracture initiation pressure is 76 MPa. During the fracture propagation, the fracture length is much greater than the fracture height and width. The fracture width is larger in the middle than on the two sides, whereas the fracture height gradually decreases at the fracture tip in the longitudinal direction until it closes and is smaller near the wellbore than at the far end. The results revealed that the fracture width at the injection point reached the maximum value of 9.05 mm, and then it gradually decreased until the fracture width at the injection point dropped to 6.33 mm at the final simulation time. The fracture broke through the upper and lower barriers due to the dominance of the effect of the interlayer principal stress difference on the fracture propagation shape, causing the hydraulic fracture to break through the upper and lower barriers. The results of the physical simulation experiment revealed that after hydraulic fracturing, multiple primary fractures were generated on the side surface of the specimen. The primary fractures extended, inducing the generation of secondary fractures. After hydraulic fracturing, the width of the primary fractures on the surface of the specimen was 0.382–0.802 mm, with maximum fracture widths of 0.802 mm and 0.239 mm, representing a decrease of 70.19% in the maximum fracture width. This work yielded an important finding, i.e., the urgent need for hydraulic fracturing adaptation promotes the three-dimensional development of a gas shale play.

Correction: Phase-Field Simulation of Hydraulic Fracturing by CO2 and Water with Consideration of Thermoporoelasticity

Correction: Phase-Field Simulation of Hydraulic Fracturing by CO2 and Water with Consideration of Thermoporoelasticity

An efficient computational framework for height-contained growing and intersecting hydraulic fracturing simulation via SGBEM–FEM

An efficient computational framework to model the growth of intersecting height-contained hydraulic fractures is proposed. The fracture in solids is modeled by the classical theory of linear elastic fracture mechanics, whereas the injection flow in hydraulic fractures is treated as channel flow. The governing equations of fracture mechanics are formulated in terms of weakly-singular weak-form boundary integral equations, with the knowledge of the fracture surface geometry exploited to reduce the integral dimension. The fluid flow within the fracture is treated using finite element method as one dimensional flow in an arbitrarily curved channel. The symmetric Galerkin boundary element method and finite element method are coupled with the traction continuity condition. The model is then formulated in a variational form and augmented with Lagrange multipliers to prescribe displacement constraints on intersections of hydraulic fractures, while fluid constraints are enforced by a consolidation of associated pressure degrees of freedom. Pertinent numerical implementation techniques, including spatial and temporal discretizations, special crack tip element, crack propagation criteria and remeshing strategy, are presented. The proposed framework is verified by comparing to the numerical results from a three dimensional hydraulic fracturing simulator and then verified by comparing the stress intensity factors to the XFEM and Murakami’s results for both star shaped cracks and symmetric branched cracks. The verification shows the utility properly enforces the physical constraints on the intersections of fractures. Three numerical examples are shown to demonstrate the capability of the proposed computational framework modeling the intersecting hydraulic fracturing process in a single or separated height-contained pay zones.

Opening-dependent phase field model of hydraulic fracture evolution in porous medium under seepage-stress coupling

In this paper, a seepage-stress coupling numerical analysis method is developed to simulate complex hydraulic fracturing in porous medium, in which the characteristics of hydraulic fracture evolution in porous medium under seepage-stress coupling are revealed. The classical Biot's poroelasticity theory is applied to couple the stress and fluid fields, and the crack propagation path of hydraulic fracturing is described by an opening-dependent phase field model. Potential energy caused by fluid pressure is also coupled into the governing equation of phase field evolution. The system of fracture opening affecting fluid flow is established. Staggered iterative scheme is applied to solve the above three-field coupled problem based on Newton–Raphson iterative algorithm. Three classical cases are presented to validate the proposed method: the first one is an analytical solution of pressure distribution in a fixed opening crack and the second one is a benchmark case of Sneddon analytical solution for a pressurized pre-crack and the third one is the KGD problem for hydraulic fracture propagation. Moreover, numerical simulations of hydraulic fracturing in shale block, multi-layer and natural fractures are also investigated. The numerical results agree well with the results in published literatures. It is indicated that hydraulic fracture evolution under seepage-stress coupling can be forecasted by the proposed method. The proposed method not only provides a powerful analytical tool for the oil or gas production, but also provides assessment tools for the stability of geotechnical engineering in water rich environments.

On the layer crossing problem for a semi-infinite hydraulic fracture

This paper analyses the problem of a semi-infinite fluid-driven fracture propagating through multiple stress layers in a permeable elastic medium. Such a problem represents the tip region of a planar hydraulic fracture. When the hydraulic fracture crosses a stress layer, the use of a standard tip asymptotic solution may lead to a considerable reduction of accuracy, even for the simplest case of a height-contained fracture. In this study, we propose three approaches to incorporate the effect of stress layers into the tip asymptote: non-singular integral formulation, toughness-corrected asymptote, and an ordinary differential equation approximation of the non-singular integral formulation mentioned above. As illustrated in the paper, these approaches for stress-corrected asymptotes differ in computational complexity, the complexity of implementation, and the accuracy of the approximation. In addition, the size of the validity region of the stress-corrected asymptote is evaluated, and it is shown to be greatly reduced relative to the case without layers. In order to address the issue, the stress relaxation factor is introduced. This, in turn, allows for enhancing the accuracy of the layer-crossing computation on a relatively coarse mesh to utilize the stress-corrected asymptote in hydraulic fracturing simulators for the purpose of front tracking.

Deep neural network model for estimating montney shale gas production using reservoir, geomechanics, and hydraulic fracture treatment parameters

The development of a shale gas project requires an accurate prediction of the production potential owing to the high cost of horizontal well drilling and hydraulic fracturing treatment. Previous research developed models for estimating shale gas production based on the reservoir and hydraulic fracturing data. They reported a high degree of uncertainty in the prediction as a result of the fracture properties' locking information. This research aims to reduce the uncertainty in shale gas production prediction by developing a deep neural network (DNN) model that incorporates reservoir, geomechanics, and fracture treatment parameters to predict monthly Montney shale gas production. The DNN model, optimized using the Keras Tuner optimization tool, employs a unique architecture of eight hidden layers and integrates production time as an input feature. This allows the model to predict production rates at any time point in the reservoir's life cycle. The prediction model was developed using 102,000 simulation data and blind tested using other 18,000 unseen simulation data, which were achieved by coupling a hydraulic fracture simulator with a reservoir simulator. The model revealed an average error of 13.41%, with a promising correlation between predicted and simulated gas production rates (R2 > 0.85), and cumulative gas production (R2 > 0.89). These results demonstrate the model's accuracy in predicting Montney shale gas production and its utility in assessing the economic viability of shale gas projects. In conclusion, the research introduces an important advancement in reducing uncertainty in shale gas production prediction, providing an accurate tool that has wide applications in assessing the viability of shale gas projects and suggesting further exploration in refining the prediction techniques for other geological formations.

An implicit level set algorithm for hydraulic fracturing with a stress-layer asymptote

The capability to simulate a hydraulic fracturing process is an essential tool that can be used to optimize treatment design and increase the efficiency of field operations. In most practical cases, hydraulic fractures propagate in a multi-layered rock formation. As a result, there is a need to incorporate the effect of such heterogeneities in fracturing models to achieve an accurate prediction. To capture the layered structure of rocks, a hydraulic fracture simulator typically requires a fine mesh, which leads to a drastic reduction in computational performance. An alternative is to use more sophisticated models that are capable of providing reasonably accurate predictions even on a relatively coarse mesh. In the case of fracture growth modeling, the pivotal component of the simulation is a fracture front tracking algorithm that accounts for the layered structure of the formation. Consequently, this paper aims to extend the established Implicit Level Set Algorithm (ILSA) to account for the effect of multiple stress layers within the tip asymptote. The enhanced front tracking algorithm involves the stress-corrected asymptote that incorporates the influence of stress layers within the near-tip region. To further increase the validity region of the stress-corrected asymptote, the stress relaxation factor is introduced, and its accuracy is examined. The numerical algorithm is validated against the reference semi-analytical solutions as well as experimental observations. In addition, we investigate the sensitivity of the fracture geometry to mesh size to demonstrate that the front tracking algorithm based on the stress-corrected asymptote retains its accuracy on a coarse mesh.

Influence of Horizontal Multi-Bedding on Hydraulic Fracture Propagation in Shale Reservoirs

Artificial fractures can easily occur and propagate in shale reservoir bedding. Their height restricts the volume of fracturing modification. A physical simulation of true triaxial hydraulic fracturing was used to analyze the characteristics of fracture morphology and the fracturing curve, as well as explore the influence of horizontal multi-bedding on the hydraulic fracture propagation of shale reservoirs. The results showed that a weaker bedding strength increased bedding fracture activation and reduced the fracture height. A higher bedding density increased the fracture complexity and reduced the main fracture height. A high injection flow can easily cause morphologically complex multi-bedding fractures. A higher injected fracturing-fluid viscosity increased the layer-penetration ability of the main hydraulic fracture when it expanded and reduced the opening degree of the bedding plane. This study provides technical support for the hydraulic fracturing design of shale reservoirs.

Using fracture-based continuum modeling of coupled geomechanical-hydrological processes for numerical simulation of hydraulic fracturing

This paper describes numerical simulation of hydraulic fracturing using fracture-based continuum modeling (FBCM) of coupled geomechanical-hydrological processes to evaluate a technique for high-density fracturing and fracture caging. The simulations are innovative because of modeling discrete fractures explicitly in continuum analysis. A key advantage of FBCM is that fracture initiation and propagation are modeled explicitly without changing the domain grid (i.e. no re-meshing). Further, multiple realizations of a preexisting fracture distribution can be analyzed using the same domain grid. The simulated hydraulic fracturing technique consists of pressurizing multiple wells simultaneously: initially without permeating fluids into the rock, to seed fractures uniformly and at high density in the wall rock of the wells; followed by fluid injection to propagate the seeded fracture density hydraulically. FBCM combines the ease of continuum modeling with the potential accuracy of modeling discrete fractures and fracturing explicitly. Fractures are modeled as piecewise planar based on intersections with domain elements; fracture geometry stored as continuum properties is used to calculate parameters needed to model individual fractures; and rock behavior is modeled through tensorial aggregation of the behavior of discrete fractures and unfractured rock. Simulations are presented for previously unfractured rock and for rock with preexisting fractures of horizontal, shallow-dipping, steeply dipping, or vertical orientation. Simulations of a single-well model are used to determine the pattern and spacing for a multiple-well design. The results illustrate high-density fracturing and fracture caging through simultaneous fluid injection in multiple wells: for previously unfractured rock or rock with preexisting shallow-dipping or horizontal fractures, and in situ vertical compressive stress greater than horizontal. If preexisting fractures are steeply dipping or vertical, and considering the same in situ stress condition, well pressurization without fluid permeation appears to be the only practical way to induce new fractures and contain fracturing within the target domain.

Study of Permian Basin Provides Insight Into Parent-/Child-Well Interactions

_ This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 211899, “Results From a Collaborative Parent/Child Industry Study: Permian Basin,” by Mark McClure, SPE, ResFrac; Magdalene Albrecht, SM Energy; and Carl Bernet, Ovintiv, et al. The paper has not been peer reviewed. _ The complete paper summarizes results from a collaborative industry study involving seven operators and 10 pad-scale data sets across four different shale plays. The paper specifically focuses on a subset of the data sets from the Midland and Delaware Basins. The project had three main objectives: compare and contrast observations between data sets and basins, develop general insights into parent- and child-well interactions, and provide customized economic optimization recommendations for each individual operator and data set. The simulations reveal that economic performance can be optimized with customized selection of well spacing, job size, and landing depth based on each company’s objectives and price deck. Methods Modeling Approach. The simulations were performed with a fully integrated hydraulic fracturing, wellbore, geomechanics, and reservoir simulator. The entire life cycle of the wells is captured in a single continuous simulation. The fractures are meshed as true cracks, with apertures on the order of microns to millimeters. Constitutive relations are used to capture transitions from being mechanically open to mechanically closed and vice versa. The simulations are fully 3D, and the equations are solved with a fully coupled scheme. For efficiency, the simulations include only one or a few stages along the wells. Fracture geometry is assumed to be planar, with no more than one dominant hydraulic fracture strand propagating per cluster. The modeling approach is based on the industry’s emerging recognition that hydraulic fractures in shale are planar at large scale, while being rough and complex at small scale. In the simulator, constitutive relations are used to account for the effect of small-scale complexity on processes such as proppant transport, fluid leakoff, and fracture propagation. Modeling Work Flow. For each data set, the modeling process consisted of the following steps: 1. Gather and organize data. 2. Create an initial model based on this data. 3. Create a list of key observations from the data set that constitute the objectives for the history-matching process. 4. Present the initial model and the list of key observations to stakeholders to obtain feedback and check communication. 5. Vary simulation input parameters to match the key observations while frequently communicating with stakeholders. 6. After finalizing the history match, perform a set of sensitivity analysis simulations, varying parameters such as well spacing and parent-well age. 7. Set up an economics model and perform a quantitative optimization of net present value (NPV)/section or discounted return on investment [DROI; defined as time-discounted revenue minus time-discounted operating expense divided by time-discounted capital expenditure (CAPEX)]. The steps of this work flow are detailed in the complete paper.

A phase‐field model for hydraulic fracture nucleation and propagation in porous media

AbstractMany geo‐engineering applications, for example, enhanced geothermal systems, rely on hydraulic fracturing to enhance the permeability of natural formations and allow for sufficient fluid circulation. Over the past few decades, the phase‐field method has grown in popularity as a valid approach to modeling hydraulic fracturing because of the ease of handling complex fracture propagation geometries. However, existing phase‐field methods cannot appropriately capture nucleation of hydraulic fractures because their formulations are solely energy‐based and do not explicitly take into account the strength of the material. Thus, in this work, we propose a novel phase‐field formulation for hydraulic fracturing with the main goal of modeling fracture nucleation in porous media, for example, rocks. Built on the variational formulation of previous phase‐field methods, the proposed model incorporates the material strength envelope for hydraulic fracture nucleation through two important steps: (i) an external driving force term, included in the damage evolution equation, that accounts for the material strength; (ii) a properly designed damage function that defines the fluid pressure contribution on the crack driving force. The comparison of numerical results for two‐dimensional test cases with existing analytical solutions demonstrates that the proposed phase‐field model can accurately model both nucleation and propagation of hydraulic fractures. Additionally, we present the simulation of hydraulic fracturing in a three‐dimensional domain with various stress conditions to demonstrate the applicability of the method to realistic scenarios.

EXPRESS 3D GEOMECHANICAL MODELING FOR INPUT TO HYDRAULIC FRACTURING ON CARBONATE OILFIELDS OF BASHKORTOSTAN REPUBLIC

The work describes a method of real-time 3D modeling of mechanical properties over the entire field area for the purposes of hydraulic fracturing. The uniqueness of this modeling approach is associated with the prompt acquisition of mechanical properties along the well paths of the field, which is especially important in conditions of insufficient geomechanics data.
 Traditional three-dimensional geomechanical modeling is a time-consuming and resource-intensive process. The data often describe the mechanical properties and stress-strain state of the rocks within the current drilling or development sector of the field and do not take into account the interwell space, especially in poorly drilled areas of the field. The method of real-time 3D geomechanical modeling makes it possible to quantify values of minimum horizontal stress used in hydraulic fracturing simulators, as well as static and dynamic Young's modulus and Poisson's ratio over the entire field area using the optimal amount of resources and in a shorter time.
 Based on the built three-dimensional cubes of elastic properties and stresses, correct data were obtained in the inter-well space, their vertical and lateral changes were analyzed, and frac design data were obtained at any well drilled through the simulated targets of the field.
 This paper covers the Arlanskoye, Znamenskoye and Yugomashevskoye fields (Bashneft PJSC). The target targets are carbonate deposits: Kashira and Podolsk strata of the Arlanskoye field, Tournaisian strata of the Znamensky field and Bashkir-Vereisky strata of the Yugomashevsky field.
 For the carbonate rocks of the target targets, laboratory core studies were carried out to determine elastic properties, and stable regional core-core relationships were obtained in the intervals of lower and middle Carboniferous carbonate deposits.
 1D geomechanical models were built in RN-SIGMA software 84 wells at the intervals of the study targets. In current 3D geological models are introduced and distributed values of Young's modulus, Poisson's coefficient and minimum horizontal stress gradient is calculated. Analysis of changes in geomechanical properties by area, for each study object was carried out and data were obtained to create frac designs for 15,000 wells.

Post-frac evaluation of deep shale gas wells based on a new geology-engineering integrated workflow

The development of shale gas reservoir is now shifting focus from mid-shallow reservoirs to deep reservoirs in the southern Sichuan Basin. For such reservoirs with high temperature, pressure, and stress difference, along with multiple folds, faults, and complex fracture networks, improving the stimulation performance of shale gas wells is the ultimate challenge. This study presents a new geology-engineering integrated workflow coupling hydraulic fracture simulation and reservoir simulation together with artificial intelligence to perform post-frac evaluations. A two-step calibration workflow of fracturing and reservoir simulations generated an ensemble of representative models, and a confidence interval of estimated ultimate recovery forecast were obtained. Four deep shale gas wells with two different completion versions (version 1.0 and version 2.0) in Y101 study area were evaluated. Some of the key learnings include: (1) the ratio of stimulated rock volume and drained rock volume is quantified to 8%–25% for the four characterized deep shale gas wells; (2) the version 2.0 completion design is able to stimulate the near-well region more effectively than version 1.0; (3) this novel geology-engineering integrated workflow performed the first reliable, robust and quantifiable post-frac evaluation in the southern Sichuan Basin deep shale reservoir.

Optimization of integrated geological-engineering design of volume fracturing with fan-shaped well pattern

According to the variable toe-to-heel well spacing, combined with the dislocation theory, discrete lattice method, and finite-element-method (FEM) based fluid-solid coupling, an integrated geological-engineering method of volume fracturing for fan-shaped well pattern is proposed considering the geomechanical modeling, induced stress calculation, hydraulic fracturing simulation, and post-frac productivity evaluation. Besides, we propose the differential fracturing design for the conventional productivity-area and the potential production area for fan-shaped horizontal wells. After the fracturing of the conventional production area for H1 fan-shaped well platform, the research shows that the maximum reduction of the horizontal principal stress difference in the potential productivity-area is 0.2 MPa, which cannot cause the stress reversal, but this reduction is still conducive to the lateral propagation of hydraulic fractures. According to the optimized fracturing design, in zone-I of the potential production area, only Well 2 is fractured, with a cluster spacing of 30 m and an injection rate of 12 m3/min per stage; in zone-II, Well 2 is fractured before Well 3, with a cluster spacing of 30 m and an injection rate of 12 m3/min per stage. The swept area of the pore pressure drop in the potential production area is small, showing that the reservoir is not well developed. The hydraulic fracturing in the toe area can be improved by, for example, properly densifying the fractures and adjusting the fracture distribution, in order to enhance the swept volume and increase the reservoir utilization.