Activation Of Natural Fractures Research Articles

Activation of natural fractures during hydraulic fracturing in elastoplastic jointed rocks

Complexity of fracture development in low permeability oil and gas reservoirs is of interest to many field operators for production enhancement. In highly jointed shales such as Marcellus and Sanmin, fluid-induced shear slip deformation along joint junctions coupled with soft nature of shale fabrics make fracturing operations more complicated. Sophistication includes widely reported occurrences of seismic tremors. Understanding of slip phenomena and fracture network development in such scenarios is never straightforward and curtailed with limited lines of evidence. In this study, we propose a globally embedded cohesive zone modelling within an elastoplastic three-dimensional framework to provide an understanding of the complex fracture development in soft shale formations. Shear strength of the global pore pressure cohesive elements is obtained as a function of field variable (stress) through parallel computation with FORTRAN language. Drucker Prager frictional behavior is included in the model with different friction coefficients to ascertain the joint slip phenomena when shear strength of the joints is reduced under the drenched effect of fracturing fluid. Results indicate that when the coefficient of friction is high, the total slip of the rock is reduced compared to the scenario with low friction coefficients. Other parametric analyses indicate that an isotropic stress regime leads to a more complex fracture development, while increased injection rates favour the opening of more compressed fracture wings. The model is validated against field data from layered shale reservoir as well as against Kristianovich-Geertsma-de Klerk (KGD) model with excellent agreements in both cases. This study is important for understanding fracture development complexity in soft jointed rocks together with associated slip phenomena.

The role of natural fracture activation in hydraulic fracturing for deep unconventional geo-energy reservoir stimulation

The presence of sealed or semi-sealed, multiscale natural fracture systems appears to be crucial for the successful stimulation of deep reservoirs. To explore the reaction of such systems to reservoir stimulation, a new numerical simulation approach for hydraulic stimulation has been developed, trying to establish a realistic model of the physics involved. Our new model successfully reproduces dynamic fracture activation, network generation, and overall reservoir permeability enhancement. Its outputs indicate that natural fractures facilitate stimulation far beyond the near-wellbore area, and can significantly improve the hydraulic conductivity of unconventional geo-energy reservoirs. According to our model, the fracture activation patterns are jointly determined by the occurrence of natural fractures and the in situ stress. High-density natural fractures, high-fluid pressure, and low effective stress environments promote the formation of complex fracture networks during stimulation. Multistage or multicluster fracturing treatments with an appropriate spacing also increase the stimulated reservoir area (SRA). The simulation scheme demonstrated in this work offers the possibility to elucidate the complex multiphysical couplings seen in the field through detailed site-specific modeling.

Numerical Simulation of the Fracture Propagation Mechanism during Supercritical Carbon Dioxide Fracturing in Shale Reservoirs

Abstract To investigate the fracture propagation mechanism during supercritical CO2 fracturing in shale reservoirs, a numerical model was proposed based on the displacement discontinuity method. The Peng–Robinson equation was introduced to determine the variations in CO2 properties during the fracturing process. Considering natural fracture distribution in shale reservoirs, the fracture propagation mechanisms during supercritical CO2 fracturing in shale reservoirs under different horizontal stress differences and matrix permeabilities were analyzed. The influence of the proportion of CO2 preenergizing on fracture morphology was discussed. The results obtained via numerical simulation show that supercritical CO2 is beneficial to create a more complex fracture network by activating natural fractures under the same horizontal stress difference. CO2 easily penetrates into the matrix near the fracture surfaces, increasing reservoir energy. However, when the permeability of shale reservoirs exceeds 0.04×10−3 μm2, substantial filtration of CO2 into the reservoir matrix occurs near the well bore, limiting the activation of natural fractures around the fracture tip. A higher proportion of CO2 preenergizing during fracturing is conducive to improve the fracture complexity while reducing the fracture aperture.

Numerical simulation of hydraulic fracturing with consideration of the pore pressure distribution based on the unified pipe-interface element model

Understanding hydraulic fracture propagation behaviours is vital for optimizing fracturing design in oil and gas production. It has been observed that the stress and pore pressure distribution are much more complex during fracturing treatment as a result of long-term fluid injection and production in the reservoir. When rock is subjected to internal hydraulic pressure and external mechanical loading, the closing, opening, or other interactions of pre-existing weaknesses or induced new fractures will be altered. In this paper, a number of hydraulic simulation scenarios are performed to investigate the effect of pore pressure distribution on fracture initiation and propagation using the unified pipe-interface element method (UP-IEM). The proposed method for predicting the hydraulic fracture path in the permeable porous medium with non-uniform pore pressure field is validated with experimental results. Considering the arrangement of well patterns and natural fractures in the rock, the problems of hydraulic fracture propagation behaviours with wellbore interaction and pore pressure induced natural fracture activation are simulated. The influence of pore pressure saturation and the injection sequence of wellbores on hydraulic fracturing are researched. A sensitivity analysis is carried out to investigate the parameter effects on pre-existing fracture tortuosity, opening width and breakdown pressure under pore pressure. These numerical examples provide guidance to engineers to estimate the probability of danger or possibilities to improve the injection and production of wells.

Concurrent 18. Presentation for: Co-application of micro-proppant with horizontal well, multi-stage hydraulic fracturing treatments to improve productivity in the Permian coal measures, Bowen Basin, Australia

Presented on Wednesday 18 May: Session 18 Coal permeability is the key discriminator in well completion selection in coal wells. Low productivity is often attributed to compartmentalisation and pressure-dependent permeability (PDP) effects. Often, vertical well hydraulic fracturing is used to enhance productivity from lower-permeability coals, however, several authors have noted that coal fracture treatments can generate a large unpropped area of stimulated reservoir volume (SRV) that is generated from natural fracture activation and pressure-dependent leakoff. The result of this study confirms previous studies (using radial, cartesian, and enhanced SRV analytic models) that graded particle or micro-proppant injections in conjunction with hydraulic fracture treatments can be a means to enhance coal productivity in PDP-affected or low-permeability coals. In this work, data from the Bowen Basin will be used to investigate the implementation and benefits of micro-proppants in conjunction with horizontal well, multi-stage, hydraulic fracture treatments. The calibrated model will be based on a Bowen Basin case incorporating petrophysical, diagnostic fracture injection test (DFIT), hydraulic fracture, and can utilise production data to constrain modelling parameters. To better understand and provide guidance on co-application of horizontal, multi-stage hydraulic fracturing in conjunction with micro-proppant injections, a range of factors will be evaluated in this model including initial permeability, permeability anisotropy, fracture half-length, area and conductivity of the enhanced region between fractures, lateral length, and the number of fractures. This model will demonstrate the effectiveness, economic benefits, and optimal number of fracturing stages based on the reservoir parameters. To access the presentation click the link on the right. To read the full paper click here

Co-application of micro-proppant with horizontal well, multi-stage hydraulic fracturing treatments to improve productivity in the Permian coal measures, Bowen Basin, Australia

Coal permeability is the key discriminator in well completion selection in coal wells. Low productivity is often attributed to compartmentalisation and pressure-dependent permeability (PDP) effects. Often, vertical well hydraulic fracturing is used to enhance productivity from lower-permeability coals, however, several authors have noted that coal fracture treatments can generate a large unpropped area of stimulated reservoir volume (SRV) that is generated from natural fracture activation and pressure-dependent leakoff. The result of this study confirms previous studies (using radial, cartesian, and enhanced SRV analytic models) that graded particle or micro-proppant injections in conjunction with hydraulic fracture treatments can be a means to enhance coal productivity in PDP-affected or low-permeability coals. In this work, data from the Bowen Basin will be used to investigate the implementation and benefits of micro-proppants in conjunction with horizontal well, multi-stage, hydraulic fracture treatments. The calibrated model will be based on a Bowen Basin case incorporating petrophysical, diagnostic fracture injection test (DFIT), hydraulic fracture, and can utilise production data to constrain modelling parameters. To better understand and provide guidance on co-application of horizontal, multi-stage hydraulic fracturing in conjunction with micro-proppant injections, a range of factors will be evaluated in this model including initial permeability, permeability anisotropy, fracture half-length, area and conductivity of the enhanced region between fractures, lateral length, and the number of fractures. This model will demonstrate the effectiveness, economic benefits, and optimal number of fracturing stages based on the reservoir parameters.

Shearing Performance of Natural Joints with Different Roughnesses under Direct Shearing Tests

Roughness is one of the major characteristics of natural fracture in hydrocarbon and geothermal reservoirs, which has a significant influence on the activation of fractures during hydraulic stimulation. The main purpose of this study is to investigate the effect of different roughnesses and high normal stresses on shear behaviors of rock joints. To do this, replicas of natural rock joint surfaces were constructed using the 3D optical scanning and 3D rigid engraving technique. Direct shear tests were performed on rock joint replicas with three joint roughness coefficient (JRC) indices (i.e., 1.42, 4.98, and 7.96) at two high normal load conditions (i.e., 15 and 30 MPa). The results show that the shear strength dependence on surface roughness is similar at normal stresses of 15 and 30 MPa. In addition, JRC-JCS shear strength criterion can reasonably describe the peak shear strengths that obtained from experimental curves, and the peak shear stresses have a positive correlation with JRC values at both normal stresses. Moreover, at normal stresses of 15 and 30 MPa, the shearing mechanism of joints with different JRC values is asperity shearing off. Results also show that the friction coefficient of joint surface increases as joint roughness increases, and higher normal loads may lead to a decrease of apparent cohesion, which weakens the residual strength during the slip. The results of this study improve insight into the natural fracture activation behavior during hydraulic fracturing.

Cyclic Water Injection Potentially Mitigates Seismic Risks by Promoting Slow and Stable Slip of a Natural Fracture in Granite

Induced seismicity associated with fluid injection has raised serious concerns for the safety and efficiency of geo-energy systems. Cyclic injection has recently been proposed as an alternative injection scheme to reduce the large magnitude injection-induced seismicity. However, the influence of cyclic injection on the activation of natural fractures in granite and the resulting seismic risk is not yet clear. This study investigates the injection-induced activation of a critically stressed natural fracture in a granite core sample, particularly focusing on the comparison between monotonic and cyclic water injection under pressure-controlled and volume-controlled conditions. Experimental results show that the acceleration and deceleration of fracture slip are modulated by the shear stress imbalance between the fixed shear stress and the evolving frictional strength of the fracture. Fracture slip affects the fluid pressure distribution on the fracture, which in turn regulates the frictional strength of the fracture. At a small total shear displacement (i.e., ~ 0.9 mm in this study), cyclic injection with a restricted peak injection pressure results in aseismic fracture slip at much smaller peak slip rates compared to that during the monotonic injection. On the one hand, the more uniform reduction in effective normal stress caused by cyclic injection encourages slow and stable fracture slip, characterized by the smaller peak slip rates. On the other hand, the flowback of injected fluid or suspension of injection could prevent the occurrence of fast-accelerated fracture slip during cyclic injection. However, the fracture can become unstable when it has experienced a considerable amount of total shear displacement (larger than ~ 0.9 mm in this study), and likely gained a significantly enhanced permeability. Continued injection after the unstable shut-in stage, signified by an unusual increase in slip rate and an accelerated drop in injection pressure, could result in rapid and unstable fracture slip.

New algorithm to simulate fracture network propagation using stationary and moving coordinates in naturally fractured reservoirs

AbstractInfluenced by natural fractures, fracture networks may be created when hydraulic fractures propagate in naturally fractured reservoirs. Simulating fracture network propagation is crucial to fracture design. In this paper, a two‐dimensional mathematical model for the direct simulation of fracture network propagation that considers fluid filtration and reservoir fluid flow is developed, and a simulation method is proposed based on the coupled flow idea of natural fractures and matrices in dual‐porosity media. The model uses dynamic coordinates to represent the extended hydraulic fracture network and static coordinates to describe natural fractures that have not been activated. The activation of natural fractures by a hydraulic fracture is determined according to the hydraulic fracture propagation scenario after an intersection with natural fractures. The geometric shape and size of the network fracture are obtained by changing the size of the simulated area and solving the mass balance, fracture width, and reservoir fluid flow equations numerically in a coupled manner. After validating the new model, a parameter sensitivity analysis is conducted to study the effects of injected fluid volume, fracture height, fracture spacing, elastic modulus, horizontal principal stress difference, pumping rate, and fracturing fluid viscosity on the fracture network shape, fracture network size, average fracture width, and fracture‐reservoir contact area. The numerical results indicate that the model can be directly used to simulate the propagation of fracture networks. The volume of injected fluid is the most critical factor affecting the fracture network size. Increasing the fluid viscosity and injection rate can increase the width of the fracture network and the average width of a secondary fracture. However, the total contact area of the reservoir and fracture will decrease, and the reservoir‐fracture contact area and fracture network size will increase with a decrease in the horizontal stress difference and increase in elastic modulus. Decreasing a fracture's height can significantly increase the size of the fracture network and reservoir‐fracture contact area.

A method to experimentally investigate injection-induced activation of fractures

Natural fractures are generally well developed in most hydrocarbon and geothermal reservoirs, which can produce complex fracture networks due to the activation of fractures during hydraulic stimulation. The present paper is devoted to developing a method to investigate the activation characteristics of fracture under injection-shearing coupled condition at laboratory scale. The fluid is injected into the single-fractured granite until the fracture is activated based on the triaxial direct shear tests. The results show that injection process can significantly influence the shear stress distribution field, resulting in release of shear stress and relative slip between the opposite sides of the fractured surface. The injection-induced activation of fracture is strongly dependent on the stress states. When the normal stress increases, the injection-induced activation pressure increases, and the comparatively high normal stress can restrain the fracture activation. The fracture deformation mechanisms during fluid injection are also discussed preliminarily with the experimental data. The sensitivity of shear stress to fluid injection increases with increase of shear stress level, while it decreases under high normal stress. The results can facilitate our understanding of the natural fracture activation behavior during fluid pressure stimulation.

Fracturing Gels as Analogs to Understand Fracture Behavior in Shale Gas Reservoirs

Hydraulic fracturing is widely used in the exploitation of unconventional reservoirs, such as shale gas and tight gas. However, a full understanding of the activation of natural fractures, prediction of fracture growth, distribution of proppant, and network fracture system effectiveness remain unresolved. The onset of fracturing in the media requires energy and this is due to the buildup of pressure within the rock due to continuous injection of fluid. In other words, when the energy associated with the injection fluid reaches the fracture strength of the rock, the fracture initiates and propagates into the formation. Here, we use gelatin in hydraulic fracturing laboratory tests and compare the results to a modified radial hydraulic fracturing theory. The mechanics of the gelatin, procedures to make a testing gelatin block, and procedures to conduct the test are described. The results show that the fracture evolving behaviours from experiments are well matched by the theory. The results are then scaled up to understand fracture growth behaviour in a tight rock reservoir.

Experimental investigation of fracture initiation position and fluid viscosity effect in multi-layered coal strata

The multi-layered coal strata in Lin-Xing block of China is rich in tight sandstone gas and the coalbed methane (CBM). The feasibility of multi-gas production and the optimal layer for fracturing in multi-layers requires a better understanding of fracture vertical extension mechanism through sandstone coal interbedding. To analyze the problems, six true tri-axial experiments were conducted on the multi-layered specimens of sandstone and coal outcrops. The transition zone was simulated by the cement with certain strength and thickness. In the experiments, the perforation position, fluid viscosity, and lithological difference were discussed. The results showed that the effect of viscosity exhibited a stepped manner as a function of fracture complexity. High-viscosity fluid significantly improved the fracture penetration ability when fracturing in coal layer. The results also show that when indirectly fracturing in sandstone, low-viscosity fluid was under the risk of natural fracture activation near wellbore to cause fracturing failure. When both layers were perforated, complex fracture network was easily formed as multi-layers were fractured. Perforation in both sandstone and coal layers were the best method based on the fracture penetration ability and the overall fracture complexity. T-shaped and step-wise fractures were found in the interface. The transition zone made it easier for fracture vertical extension through layers. The field production data was in good agreement with the experimental results. These results provide a guideline for the optimal perforation position selection and fracturing parameters in coal strata.

Integrated Interpretation of Microseismic and Petroleum-Engineering Data for Comparison of Gas Production in Two Interfering Adjacent Wellpads in the Horn River Basin, Canada

SummaryWe present an integrated interpretation of microseismic, treatment, and production data from hydraulic-fracturing jobs carried out in two adjacent wellpads in the Horn River Basin, northeast British Columbia, Canada.We conclude that poor correlation coefficients (R2) in crossplots of normalized production rate vs. the product of stimulated reservoir volume (SRV) and porosity and total organic carbon (TOC) (SRV×ϕ×TOC) indicate pressure interference between wells or wellpads. Good correlation coefficients in the same crossplots indicate lack of interference.The SRV×ϕ×TOC product reflects the hydrocarbon pore SRV because there is a relationship between TOC and hydrocarbon saturation in shales (Lopez and Aguilera 2018). Our results suggest that natural-fracture networks have an important effect on well connectivity and on the spatial distribution of microseismic data. Connectivity between wellpads occurs through a network of pre-existing natural fractures, which are approximately perpendicular to the least principal compressive stress in the area.This conclusion is supported by data analysis from Wellpads I and II in the Horn River Basin. Wellpad I includes eight wells that were drilled and fractured in the Muskwa and Otter Park formations (four wells in each formation) in 2010. Wellpad II includes three wells drilled and fractured in 2011 in each of the three shale formations, Muskwa, Otter Park, and Evie. There is a 1-year interval between fracturing on the first and second wellpads.The data analysis includes evaluation of magnitudes, b-values, moment-tensor inversion (MTI), and the spatial and temporal distributions of three-component microseismic events recorded during more than 200 stages of fracturing by multiwell downhole arrays. We analyzed Gutenberg-Richter frequency/magnitude graphs for each fracturing stage, and with proper integration of b-values, fracture-complexity index (FCI), MTI information, and treatment data, we distinguished hydraulic-fracturing-related events and events associated with slip along the surface of natural fractures. The results are compared with 5- and 4-year gas-production data in Wellpads I and II, respectively.Identification of natural fractures and information about interactions between hydraulically fractured wells are both essential for optimal well placement and completion, reservoir characterization, SRV calculation, and reservoir simulation. This study presents a distinctive insight into the integrated interpretation of microseismic events and production data to identify the activation of natural fractures and interference between the hydraulically fractured wells. The methodology developed in this study is thus related to production engineering, but examines it from the point of view of microseismic data.

Observing the effects of transition zone properties on fracture vertical propagation behavior for coal measure strata

The transition zone is a typical interface with enough thickness and high heterogeneity between the sandstone and coal and has a great effect on the fracture propagation in coal measure strata. In the study, the true tri-axial experiments were conducted with the combination of sandstone, coal and limestone outcrops. The effect of cementing strength and thickness of the transition zone was mainly studied. Three types of hydraulic fracture initiation positions were used to simulate three fracturing situations in the field. The results showed that the effect of the transition zone on the fracture vertical extension could be concluded: the fracture was easy to cross or slip with low cementing strength and turned inside the transition zone with high cementing strength; the fracture tended to branch or be blocked by the thick transition zone. The horizontal flow through face cleats and natural fracture activation in coal contributed to a more developed fracture network. The characters of pumping curve pressure “increasing – fluctuation – dropping”, and the “fluctuation pressure more than initiation pressure” indicated the interface crossing. The results of experiments agreed with the previous numerical simulation and helped to optimize the fracturing design in layered coal strata.

Modeling Dynamic Behaviors of Complex Fractures in Conventional Reservoir Simulators

Summary Field data have shown the decline of fracture conductivity during reservoir depletion. In addition, refracturing and infill drilling have recently gained much attention as efficient methods to enhance recovery in shale reservoirs. However, current approaches present difficulties in efficiently and accurately simulating such processes, especially for large-scale cases with complex hydraulic and natural fractures. In this study, a general numerical method compatible with existing simulators is developed to model dynamic behaviors of complex fractures. The method is an extension of an embedded discrete-fracture model (EDFM). With a new set of EDFM formulations, the nonneighboring connections (NNCs) in the EDFM are treated as regular connections in traditional simulators, and the NNC transmissibility factors are linked with gridblock permeabilities. Hence, manipulating block permeabilities in simulators can conveniently control the fluid flow through fractures. Complex dynamic behaviors of hydraulic fractures and natural fractures can be investigated using this method. The proposed methodology is implemented in a commercial reservoir simulator in a nonintrusive manner. We first present one synthetic case study in a shale-oil reservoir to verify the model accuracy and then combine the new model with field data to demonstrate its field applicability. Subsequently, four field-scale case studies with complex fractures in two and three dimensions are presented to illustrate the applicability of the method. These studies involve vertical- and horizontal-well refracturing in tight reservoirs, infill drilling, and fracture activation in a naturally fractured reservoir. The proposed approach is combined with empirical correlations and geomechanical criteria to model stress-dependent fracture conductivity and natural-fracture activation. It also shows convenience in dynamically adding new fractures or extending existing fractures during simulation. Results of these studies further confirm the significance of dynamic fracture behaviors and fracture complexity in the analysis and optimization of well performance.

Hydro-mechanical modeling of hydraulic fracture propagation and its interactions with frictional natural fractures

Hydraulic fracturing is a key technique to activate natural fracture networks aiming at increasing permeability of non-conventional reservoirs. In order to design effective stimulations, it is necessary a good understanding of the hydraulic fracture propagation and its interaction with natural fractures. A robust methodology was developed using the finite element method to study the mechanisms that influence the activation of natural fractures and the subsequent process of hydraulic fracture propagation. An innovated mesh fragmentation technic is developed to simulate hydraulic fracture propagation with arbitrary paths. The behavior of the hydraulic fracture is modeled using hydromechanical cohesive interface elements with progressive damage model. The Mohr-Coulomb criterion with tension cutoff is incorporated to represent the frictional behavior of natural fractures. The developed methodology is validated through literature data on experimental test results. The three main possibilities of interaction events (opening, crossing and arrest) are predicted accurately. Subsequently, the effect of some primary parameters such as the angle of approach between hydraulic and natural fracture, the stress ratio between minimum and maximum horizontal stresses and the internal friction angle of the natural fracture were studied to provide a better insight of the propagation processes of the hydraulic fracture. An interaction response diagram is proposed combining the effects of those parameters to provide a good estimative of fracture interaction.

Numerical evaluation of shear and tensile stimulation volumes based on natural fracture failure mechanism in tight and shale reservoirs

Although many scholars have put forward the methods and models to predict the stimulated reservoir volume (SRV), the mathematical models do not reflect well the mechanism of SRV development. In addition, the effects of relative fracture treatment and reservoir parameters on different stimulation areas are not well understood. During the process of hydraulic fracture propagation, fracturing fluid leak-off from the main fracture due to the activation of natural fractures can elevate the reservoir pore pressure, resulting in shear slippage and tensile failure of the natural fractures and, finally, in microseismic events. Different stimulation regions, including tensile failure zone, shear failure zone, and swept region, may co-exist along the activated natural fracture. In this study, a new mathematical model was presented based on the shear slippage and tensile failure criterion of weakness plane, hydraulic fracture propagation model, mechanical conditions of natural fracture activation, fluid diffusivity equation, and using a shear dilation model to characterize the reservoir permeability variation after shear slippage of the natural fractures, so as to better describe the growth of SRV. The model was also verified by matching field microseismic monitoring data. Then, the effects of azimuth angle and horizontal principal stress difference on the shear and tensile failure pressure of natural fractures, permeability enhancement, and critical net pressure of main fracture to activate natural fractures were illustrated. The impacts of treatment fluid viscosity, natural fracture azimuth angle, and horizontal stress difference on the reservoir pore pressure, SRV shape distribution, different SRV sizes, and SRV bandwidth and length were also analyzed. The results indicated that increasing the horizontal stress difference decreased the tensile failure area but increased the shear slippage zone sharply. Both shear and tensile failure regions decreased on increasing the natural fracture azimuth angle from 30° to 50°. Increasing the fluid viscosity from 1 to 10 mPa·s expanded the size of the tensile failure zone but reduced the shear slip zone.

Numerical simulation of hydraulic fracture propagation in naturally fractured formations using the cohesive zone model

This paper presents an integrated methodology that utilizes the cohesive zone model (CZM) to simulate propagation of hydraulic fractures, and their interactions with pre-existing natural fractures. CZM has the advantage of capturing the non-elastic behavior of shales; usually induced by total organic carbon (TOC) as well as dissimilar mechanical properties of cemented natural fractures. At the intersection of an advancing hydraulic fracture and a stationary natural fracture, the hydraulic fracture may arrest, cross, or divert into a pre-existing natural fracture depending on the rock mechanical properties, magnitude and direction of rock principal stresses, and fracture intersection angle. The activation of natural fractures during hydraulic fracture treatments improves fracture complexity and expands reservoir drainage area, making stimulation treatments more effective. In this work, triaxiality effects are incorporated into the cohesive zone model. Utilizing triaxiality makes the traction separation law (TSL) tied to confining pressure and this ensures a more reliable transition from laboratory test environment to bottomhole conditions. We present a methodology to determine the cohesive properties or TSL characteristics of rock, after performing semicircular bending tests (SCBT). Finite element analysis (FEA) is then used to calibrate the cohesive properties of both rock and natural fractures. The calibrated parameters were utilized in a field-scale FEA to simulate the growth of complex fracture networks. The results show how fracture intersection angle and the nature of cemented materials inside the natural fractures might divert a hydraulic fracture initially propagating in a direction perpendicular to the minimum horizontal stress. The sensitivity analysis of primary parameters such as fluid viscosity, natural fracture distribution, fracture intersection angle, and differential stresses is implemented to provide a better insight into the performance of hydraulic fracturing jobs in naturally fractured reservoirs. Results indicate the importance of nonlinear fracture tip effects as in-situ stress differences increase.

Integrated fracability assessment methodology for unconventional naturally fractured reservoirs: Bridging the gap between geophysics and production

Fracability evaluation in unconventional reservoirs is one of the most important initiatives for economic success. Most evaluation methods in geophysics and well logging are based on calculating rock mechanical properties, in which a frequently used term is brittleness. However, oil and gas production, mainly determined by effective natural fracture networks in unconventional low-permeability reservoirs, is the final goal of reservoir stimulation. In this work, a novel integrated methodology was proposed to correlate conventional post-stack seismic data to well production rate. It aims to pre-evaluate regional stimulation performance, facilitating investment decision-making in line with global oil prices and environmental consideration. Structural occurrence, seismic maximum curvature, and geomechanics parameters were combined in a physical model to evaluate underlying development and activation of natural fractures, result in the activation index F1. The potential of artificial induced fractures were quantified as normalized index F2 by integrating mechanical item based on fracture mechanics and fluid flow. Accordingly, a fracability sweetness index (Fsweet) model was built to correlate standardized well production rate (Qeff). A Case study of a naturally fractured igneous reservoir with 8 wells showed agreement between Fsweet and Qeff. A considerable part of highly active fractures with F1 of [0.9, 1] distributed over the area with lower curvature value. By contrast, the majority of fractures with lower F1 of [0.8, 0.9] located in zone with higher curvature value. The weight ratio α=0.06 indicated that in this case the overwhelming production contribution were from natural fractures, which were evidenced by well core picture. The field data demonstrates the prospect for predicting regional fracability variation, and suggests that it is possible to correlate fracability index with standardized well production rate. The insights contribute to well placement optimization and stimulation treatment design, breaking limitation of engineers' influence on individual wells, and hence reducing exploitation cost while enhancing ultimate recovery.

Experimental investigation of proppant settling in complex hydraulic-natural fracture system in shale reservoirs

The general development mode of shale gas reservoirs, as an unconventional resource, cannot yield good results. Hydraulic fracturing is a widely used method in the development of unconventional reservoirs. This method’s nature is to create hydraulic fractures in the reservoir, providing a flow path for oil and gas. To achieve a satisfying output, fracture dimensions matter greatly, as well as the fracture effective period. Maintaining these parameters requires that proppant can be distributed in fracture systems abundantly and evenly such that reservoirs can have durable fractures with good conductivity.Shale gas reservoirs have small porosity and permeability. Gas contained in them is difficult to exploit; thus, massive stimulation methods are needed. Conventional fracturing usually aims to create a long single planar fracture in a reservoir, while in shale gas reservoirs, complicated fracture networks are needed. Thus, the fracturing method in shale gas reservoirs should take natural fractures into consideration, link original micro-fractures in the reservoir, and increase the drainage area as much as possible. This type of fracturing method is called volume fracturing. Volume fracturing can also create multiple artificial fractures perpendicular to the main fracture, improving the stimulation effect and extending the stimulation effective period.Proppant distribution is critical to maintaining fracture network conductivity and enhancing a shale gas reservoir’s output. Moreover, proppant migration and settling during fracturing can affect the activation of natural fractures and the formation of fracture networks greatly, as well as the final effective fracture geometry. The body of research concerning proppant’s distribution law in conventional single fractures is quite mature, but the distribution law in complicated fracture networks has not been thoroughly elucidated. Obviously, the current understanding cannot satisfy the demand of practical stimulation. This paper considers the difference of the proppant distribution law between complicated fracture networks and conventional fractures and uses a self-designed complex fracture network simulation device to study proppant migration and the settling law in a complicated fracture network. The research results provide theoretical support for fracturing design in shale gas reservoirs.