Fracture Wing Research Articles

An Analytical Method for Determining the Bottom‐Hole Pressure of Vertical Well With Multiple Fractures

Hydraulic fracturing has been a common treatment to enhance well productivity, especially in tight oil and gas reservoirs. Studying the pressure response characteristics of fractured reservoir has been a hot topic due to the significant contribution of fractures to conductivity enhancement. Because of the difficulty in describing the flow problems in vertical fractured well and the lack of related literatures, a novel method to determine the bottom‐hole pressure of a vertical well with multiple fractures based on Newman product method is proposed in this paper. First, the physical model and corresponding mathematical model are established. Then, the solution of bottom‐hole pressure can be obtained through Laplace transformation. Sequentially, the validations of computational method and computational codes contain are presented. From the view of curve fitting and interpretation results, the calculations in this paper are in good agreement with the previous numerical results and our computation method is reliable. Next, a group of typical curves are generated to analyze the flow regimes. And a series of curves are generated to demonstrate effects of key parameters on curve shape. The results indicate that increasing the fracture wings, fracture intersection angle, and fracture length uniformity can enhance the well productivity. Lastly, a case study is exhibited to show the application of the proposed method.

Investigation into contributions of fracture geometry characterization and interference to productivity of multi-fractured vertical gas well

Vertically fractured wells have been widely used to develop tight gas reservoirs. Characterizing the geometry of fractures created by hydraulic fracturing is a key factor influencing the productivity of such wells. Appropriately modeling the shapes of actual fractures is thus important for accurately predicting the well productivity. Past research in the area has tended to simplify fractures into straight lines, but this does not adequately represent the complex hydraulic fractures encountered in fractured reservoirs. In this study, we propose a generalized model for the productivity of a vertically fractured well to capture the characteristics of hydraulic fractures in gas fields. The proposed model accounts for several relevant mechanisms, including Knudsen slippage, characteristics of complex fracture geometry, and interference caused by multiple fractures. We validate the proposed model by applying it to a series of cases considered in the literature, and analytically examine key parameters such as the fracture number Nf and characteristics of the fracture geometry, including the length ratio a, width ratio b, branching angle θ and level n, fracture penetration ratio l0re, asymmetry in the length of fracture wing, and fracture intersection angle φ et al. The results show that there is a small drop in pressure between the inlet and outlet of the fracture. The well productivity is found to be positively associated with Nf, l0re, φ, and asymmetry in the length of the fracture wing. Furthermore, the productivity of a well intercepted by tree-shaped fractures primarily depends on a and n, and is almost entirely unaffected by b. By contrast, the well productivity gradually decreases with increasing θ. A tree-shaped fracture significantly enhances the well productivity by 110% (a=0.9, n=3), compared with a straight fracture. Finally, we provide an approach to increase the productivity of vertical wells based on the findings of this study.

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.

A HYBRID NUMERICAL/ANALYTICAL MODEL OF TRANSIENT SEEPAGE FOR VERTICAL FRACTURED WELL IN TIGHT GAS RESERVOIR BY USE OF FRACTAL THEORY AND CONFORMAL MAPPING METHOD

Insufficient consideration of the complex morphology of hydraulic fractures (HF) and heterogeneous physical properties of fractured reservoirs in seepage models can result in unreliable well testing analyses. The fractal porosity and permeability (FPP) model provides an effective method for characterizing reservoir heterogeneity in the near-wellbore zone. However, its application to scenarios involving irregularly-shaped hydraulic fracture networks and multiple fracture clusters is challenging due to the lack of spatial symmetry. To address this issue, this paper proposes a combined approach of FPP and conformal mapping (FPP-CM) to transform the region of fractured formation into the exterior of the unit disk domain using numerical conformal mapping. The transient seepage flow model of the vertical fracture well (VFW) is then established by coupling it with the FPP model. The typical curve of pressure transient behavior with the division of flow stages was plotted, and the model verification and sensitivity analysis of parameters were conducted. The results indicate that the fractal dimension primarily affects the formation linear flow stage and its subsequent flow stages; with a decrease in fractal dimension resulting in an increase in the position of the typical curve. For VFW with multiple HF wings, a decrease in the included angle of fracture wings causes an increase in the heterogeneity distribution of microfracture physical properties, resulting in an increase in the position of the pseudo-pressure derivative curve during the late flow stage.

A Semi-Analytical Model of an Off-Center Multi-Wing Fractured Well in a Low-Permeability Gas Reservoir

Summary Since there are several hydraulic fractures around a wellbore after a large-scale hydraulic fracturing and the well is not in the center of the reservoir, no corresponding semianalytical model for wellbore pressure analysis has been proposed. To bridge this gap, this paper aims to present a semianalytical model of the off-center multiwing fractured well. With consideration of permeability stress sensitivity, the reservoir model and hydraulic fracture model are established, respectively. The coupling approach of the reservoir model and hydraulic fracture model is used to obtain the wellbore pressure solution. Meanwhile, the off-center multiwing fractured well is verified with a numerical solution. The seven flow regimes can be distinguished according to the characteristics of the pressure derivative curve. Furthermore, the effect of different fracture distributions on wellbore pressure and the derivative curve is discussed and analyzed. Assuming that the fracture wing number is equal to the average length of all fracture wings, the wellbore pressure is lowest before the radial flow regime when the fracture wing has a uniform distribution around the angle and all fracture wings are equal in length. Besides, the influence of other important parameters (fracture wing number, off-center distance, etc.) is discussed. According to the analysis, we conclude that fracture wing number has a significant influence on the pressure and derivative curves before the radial flow regime. The off-center distance has no influence on the pressure and derivative curve before the radial flow regime, but it has an obvious influence on arc boundary reaction time. Finally, the advantages of the semianalytical solution are fast calculation speed and high calculation accuracy (especially in the early flow regime).

Study On Productivity Improvement Of Low Permeability Gas Reservoir By Hydraulic Fracturing

The C5 well completed in the LZ tight gas limestone reservoir of C field is considered very good candidate for stimulation by hydraulic fracturing for the following reasons. The reservoir gross thickness of 127 ft is thick enough. Long fractures can be created. Penetrated zone is far from lowest known gas. The permeability of 0.2973 mD and the absolute open flow potential of 2.3 MMscf are low. Estimated proven gas accumulation of 24.5 Bscf is significant. Crosslinked Gel + Hi Temp Stabilizer is used as fracturing fluid due to high temperature reservoir of 334oF. High-strength of Sintered Bauxite proppant with 20/40 mesh sand is selected for this high stress formation of reservoir rock. The desired propped fracture width is 0.1004 inch. The fracture height is approximately 62.5 ft based on the half height from the centre depth of reservoir upward and downward. The propped fracture halflengths are predicted by Perkins-Kern-Nordgren model. Prediction shows that to have the propped fracture half-gths of 1335, 1587, 1850, 2114, 2356, 2576 and 2640 ft for the propped fracture width of 0.1004 inch and the fracture height of 62.5 ft, the required proppant weight in one fracture wing are 139,167,195,221, 246, 271 and 278 Mlbs respectively. With the obtained propped fracture halflengths, the productivities improvement (J/Jo) are 13.8, 16.4, 19.2, 21.9, 24.4, 26.7 and 27.3

Pressure behavior of multi-stage fractured horizontal well in a laterally non-uniform reservoir

Formation heterogeneity is very common in practice, where the reservoir usually consists of several regions with dissimilar properties separated by discontinuities. Because of the effect of the heterogeneity, there are few literatures studying the pressure response of multi-stage fractured horizontal (MSFH) wells in a laterally non-uniform reservoir. In this work, considering the linearity of the governing equations for describing fluid flows, the Laplace-domain point-source solution for three-region linear composite reservoirs is derived, based on which seepage model for an MSFH well in a laterally non-uniform reservoir is established. Fracture discrete scheme and Stehfest algorithm are used to solve the established model for an MSFH well. The validation of the proposed model is conducted by comparing with the simplified semi-analytical models in literatures and the commercial numerical simulator, which shows that our results match well with both analytical results and numerical results. Pressure behavior of an MSFH well in laterally non-uniform reservoirs is analyzed thoroughly based on the proposed model. It is found that the pressure behavior is significantly influenced by formation heterogeneity, well location, and well properties. The study provides a point-source function method for calculating pressure solutions of MSFH wells in three-region linear composite reservoirs, which can be easily extended to other complex well types besides MSFH wells, such as MSFH wells with stimulated reservoir volume, and fractured vertical wells with multiple fracture wings.

Semi-analytical modeling for multi-wing fractured vertical wells in a bilaterally heterogeneous gas reservoir

Many prolific hydrocarbon reservoirs show the lateral heterogeneity of rock properties, where the formation is composed of several regions with different rock properties separated by linear interfaces. Although there have been many studies on laterally heterogeneous reservoirs by linear composite models, most of them focus on vertical well without hydraulic fracturing. The modeling for fractured vertical wells in laterally heterogeneous reservoirs remains limited. The goal of this study is to develop a semi-analytical three-region linear composite model for multi-wing fractured vertical (MWFV) wells in a bilaterally heterogeneous gas reservoir. This model can take into account the common situation in practice, where the heterogeneity occurs on both sides of the reservoir region with the MWFV well. Based on the point-source function method, a semi-analytical modeling for an MWFV well in a bilaterally heterogeneous gas reservoir is developed by using pressure drop superposition, fracture wing discretization, and Stehfest algorithm. Compared with the simplified semi-analytical and numerical models, the correctness of the present model is verified. Log-log type curves for MWFV wells in a bilaterally heterogeneous gas reservoir are drawn. The flow regimes of the MWFV well in a bilaterally heterogeneous gas reservoir are identified. The influences of some well and reservoir parameters on the pressure response and rate decline of MWFV wells are investigated thoroughly. It is found that the pressure response and rate decline of MWFV wells are significantly affected by the well location, fracture wing properties, and reservoir heterogeneity.

Towards improved identification of obsidian microblade and microblade-like debitage knapping techniques: A case study from the Last Glacial Maximum assemblage of Kawanishi-C in Hokkaido, Northern Japan

Until recently, several hypotheses on the origin(s) and dispersion of microblade technology in Northeast Asia have been presented and discussed. Although various definitions of microblade and bladelet have been proposed in diverse geographic and chronological contexts, several researchers may agree that the pressure knapping technique for microblade production plays a paramount role in the process of significant changes in lithic technology and human behaviours between marine isotope stages (MIS) 3 and 2. One of the main topics in the study of microblade technology in Northeast Asia is establishing a systematic and reliable method for identifying microblade knapping techniques that are quantitatively verified. This paper attempts to present a more improved method for identifying microblade knapping techniques by dealing with the analysis of fracture wings which are the reliable indicators of the crack velocity. The focus of this paper is on identifying obsidian microblade-like debitage knapping techniques in the Last Glacial Maximum (LGM) assemblage of Kawanishi-C in Hokkaido, Northern Japan. The results of fracture wing analysis show that the microblade-like longitudinal debitage production at the Kashiwadai-C site was employed by not pressure but percussion techniques. This gives new insights into the diversity of microblade and microblae-like debitage reduction sequences in the LGM Hokkaido and complex process of significant changes in lithic technology, especially in relation to the emergence of microblade technology. In addition, this study shows that the analysis of fracture wings can allow appropriate technological evaluation of the microblades and microblade-like longitudinal debitage production in the period before and around the LGM in Northeast Asia.

Transient Pressure Analysis of a Multiple Fractured Well in a Stress-Sensitive Coal Seam Gas Reservoir

This paper investigates the bottom-hole pressure (BHP) performance of a fractured well with multiple radial fracture wings in a coalbed methane (CBM) reservoir with consideration of stress sensitivity. The fluid flow in the matrix simultaneously considers adsorption–desorption and diffusion, whereas fluid flow in the natural fracture system and the induced fracture network obeys Darcy’s law. The continuous line-source function in the CBM reservoir associated with the discretization method is employed in the Laplace domain. With the aid of Stehfest numerical inversion technology and Gauss elimination, the transient BHP responses are determined and analyzed. It is found that the main flow regimes for the proposed model in the CBM reservoir are as follows: linear flow between adjacent radial fracture wings, pseudo-radial flow in the inner region or Stimulated Reservoir Volume (SRV), and radial flow in outer region (un-stimulated region). The effects of permeability modulus, radius of SRV, ratio of permeability in SRV to that in un-stimulated region, properties of radial fracture wings, storativity ratio of the un-stimulated region, inter-porosity flow parameter, and adsorption–desorption constant on the transient BHP responses are discussed. The results obtained in this study will be of great significance for the quantitative analyzing of the transient performances of the wells with multiple radial fractures in CBM reservoirs.

Transient Flow of a Horizontal Well with Multiple Fracture Wings in Coalbed Methane Reservoirs

Horizontal wells with multi-stage fractures have been widely used to improve coalbed methane (CBM) production from coalbed methane reservoirs. The main focus of this work is to establish a new semi-analytical method in the Laplace domain and investigate the transient pressure behavior in coalbed methane reservoirs. With the new semi-analytical method, flow regimes of a multi-fractured horizontal well in coalbed methane reservoirs were identified. In addition, the sensitivities of fracture conductivity, diffusion model, storability ratio, inter-porosity flow coefficient, adsorption index, fracture spacing, fracture asymmetry, non-planar angle, and wellbore storage were studied. Results indicate that six characteristic flow regimes can be identified for multi-fractured horizontal wells in coalbed methane reservoirs, which are bilinear flow, first linear flow, desorption-diffusion flow, first pseudo-radial flow, second linear flow, and second pseudo-radial flow. Furthermore, the sensitivity analysis shows that the early flow is mainly determined by the fracture conductivity, the asymmetry factor, the non-planar angle, and the wellbore storage; while the desorption-diffusion flow regime is mainly influenced by the diffusion model, the storability ratio, the inter-porosity flow coefficient, the adsorption index, and the fracture spacing. Our work can provide a deep insight into the fluid flow mechanism of multi-fractured horizontal wells in coalbed methane reservoirs.

Semi-analytical model of a multi-wing fractured vertical well in linear composite reservoirs with a leaky fault

Hydrocarbon-bearing reservoirs are usually divided into multiple compartments with distinct properties by linear leaky faults. This kind of heterogeneous reservoir is usually called linear composite reservoir. Hydraulic fracturing is an important technology to significantly improve oil/gas production, and has been widely applied to the development of various oil/gas reservoirs. However, the literature on analytical/semi-analytical models for multi-wing fractured vertical (MWFV) wells in linear composite reservoirs is rare. In this work, we first derive the Laplace-space point source solution for linear composite reservoirs separated by a partially communicating fault, and then propose a semi-analytical model of MWFV wells in linear composite reservoirs based on superposition principle and fracture discrete scheme. The proposed model is validated by comparing with the published simplified models and the commercial numerical simulator. Type curves of MWFV wells in linear composite reservoirs are obtained and the flow regimes are identified. The effect of key parameters on transient pressure responses is discussed in detail. The proposed model can be employed to efficiently deal with multiple fracture wings emanated from the wellbore in linear composite reservoirs. This paper will be helpful to further develop analytical/semi-analytical models for other complex well types in linear composite reservoirs with a fault.

Model for Asymmetric Hydraulic Fractures with Nonuniform-Stress Distribution

Summary Engineers commonly expect symmetric fracture wings in multiple-transverse-fracture horizontal wells. Microseismic surveys have shown that asymmetric hydraulic fractures grow away from the recent fractured wells and grow toward previously produced wells. This might be caused by the elevated stress around the recently fractured well and the reduced stress near the depleted wells. This paper presents the asymmetric fracture growth observed by the microseismic events, develops a simple model to simulate the fracture propagation, and discusses its effect on the well productivity. Motivated by the microseismic observations, we developed a simple 2D fracture model to simulate asymmetric fracture wings that can capture the behavior of fracture hits between two adjacent horizontal fractured wells. Fluid leakoff during fracture propagation is considered in the model. The effect of asymmetric fractures on production is evaluated with numerical simulations. The newly developed fracture model shows that the fracture can grow asymmetrically if the horizontal well is near where the stress field is different between its two sides. Numerical simulation is used to quantify the productivity reduction caused by asymmetric hydraulic fractures. Our results provide a reason for why asymmetric fractures occur and demonstrate that they do penalize well performance. Our model suggests the importance of fracturing under a balanced-stress distribution that benefits long-term production. Use of this model also suggested that an optimized hydraulic-fracturing-treatment design will improve the overall performance of multiple parallel wells, which minimizes or avoids asymmetric fracture wings. The fracture-propagation model and productivity model provide simple but profound guidelines for well-pad management, including well spacing, stage planning and spacing, and completion and production order.

Use of Far-Field Diverters To Mitigate Parent- and Infill-Well-Fracture Interactions in Shale Formations

Summary Hydraulic-fracturing treatments in shale infill wells are often impacted by existing parent-well depletion and asymmetrical fracture growth. These phenomena can result in excessive load-water production, deposition of proppant and deformation of casing in the parent well, and unbalanced stimulation of infill wells. This study determines the effectiveness of particulate materials (i.e., far-field diverting agents) for mitigating the above negative outcomes by bridging near the extremities of dominant fracture wings. Fracture propagation was modeled to characterize the width profile at fracture extremities in a depleted-stress environment. A slotted-disk device was used to evaluate and optimize particulate blends for bridging slots representative of width near the fracture tip. Rheological tests replicating the downhole environment were used to formulate a system for transporting the diverting materials. Statistical analysis of 511 fracture hits at 30 parent wells was performed on key treatment indicators by the category of diverter type and post-hit parent-well condition. Production trends of the influenced wells were compared to area-specific type curves and offset wells without diverter trials. On the basis of the simulation and testing results, two types of high-graded far-field diverter systems were field-tested in a shale play: dissolvable, extremely fine particulate mixed with a 100-mesh sand, and mixtures of a nominal 325-mesh silica flour and a 100-mesh sand. Proppant dust collected at the fracturing site was also evaluated for replacing commercial silica flour. High-graded blends of the above diverting systems demonstrated superior fracture-hit and productivity metrics as compared to the base case of not applying far-field diverters. The silica flour and 100-mesh-sand mixture performed on a par with the significantly more expensive blend of dissolvable fine particulate and 100-mesh sand. Borate-crosslinked-guar gel was an effective carrying fluid for transporting diverting materials to the fracture extremities. Statistical analysis of fracture-hit events shows that the application of far-field diverters did not reduce the magnitude of pressure buildups during fracture hits; however, it significantly increases the post-hit pressure-falloff rate at the parent wells. On the basis of the area-specific type curves, pumping far-field diverters increased the P50 estimated ultimate recovery (EUR) by approximately 6% compared with the base cases of not applying diverters. For all the wells impacted by far-field diverters, the infill wells saw larger benefits with an increment of P50 EUR by approximately 7% compared with the parent wells.

Microseismic monitoring of a tight light oil reservoir: A case history in the Cardium Halo Play, Alberta

The effectiveness of hydraulic-fracturing completions in a tight-oil play is investigated by detailed interpretation of microseismicity. The microseismic programs were acquired in the Cretaceous Cardium light oil sandstone reservoirs in Alberta, Canada. Events with magnitudes between [Formula: see text] and [Formula: see text] are located by downhole monitor wells to a maximum distance of 525 m, enabling inference of the fracture wing length, height, and azimuth based on event distribution. The fracture ports, one per stage, were located in an open-hole configuration that used external packers for zonal isolation. During completions, the ports were opened with ball-actuated frac sleeves. Event distributions indicated that, in some cases, fractures grew preferentially away from the Rocky Mountain deformation front. This inferred that fracture asymmetry is independent of the position of the monitoring array, indicating that it cannot be ascribed to observation bias and suggesting that the direction of fracture growth was dominantly influenced by the preexisting stress conditions in the reservoir. The distribution of microseismicity further indicates that isolated event clusters occur 30–50 m above the reservoir. These out-of-zone events are interpreted to have occurred on unpropped fractures. In comparison with gelled oil or foamed water, slickwater fracturing fluids are shown to produce more diffuse and scattered microseismic expression accompanied by better cumulative oil production. Taken together, the results of these studies indicate that the use of slickwater fracturing fluid, along with the reduced stage spacing and tighter interwell spacing, is expected to lead to higher initial production as well as higher estimated ultimate recovery.

Numerical investigation of effect of natural fractures on hydraulic-fracture propagation in unconventional reservoirs

Field observations show that natural fractures are commonly presented in unconventional reservoirs, acting as planes of weakness that divert hydraulic fracture propagation and generate complex fracture geometry. We systematically investigated the impacts of natural fractures on net injection pressure, fracture geometry, fluid volume distribution, and induced stresses using a complex fracture propagation model. The model fully couples rock deformation and fluid flow in the fractures, perforations, and the wellbore. A simplified three-dimensional displacement discontinuity method is used to calculate multiple fracture interaction within stages as well as between stages and wells. Fluid volume distribution between each fracture is automatically calculated during pumping based on fluid resistance. The simulation results show that when a hydraulic fracture diverts into a natural fracture, the net injection pressure is elevated, resulting in width enlargement of the fracture segment before the natural fracture and reduction of total fracture length. Much less fluid flows into the fracture wing that diverts into the natural fracture. Due to a larger compressional stress exerting on the natural fracture, fracture width of the fracture segment on the natural fracture is restricted, which significantly affects proppant transport and distribution. Additionally, differential stress, approach angle, length of natural fractures, and relative position of natural fractures are critical parameters affecting elevation of net injection pressure as well as fracture width enlargement and restriction before and on natural fractures. As differential stress and approach angle increase, higher net injection pressure is required, shorter fracture length is created, and width enlargement and restriction before and on natural fractures are more severe. Deviation of fracture propagation from the original path is greatly affected by the length of natural fractures. The larger the natural fracture, the more deviation from the original path. This study highlights the behaviors of a hydraulic fracture diverting into a natural fracture and the final fracture geometry.

A new mathematical model of asymmetric hydraulic fracture growth

ABSTRACTHydraulic fractures generated by fluid injection in rock formations are often mapped by seismic monitoring. In many cases, the microseismicity is asymmetric relative to the injection well, which has been interpreted by stress gradient along the direction of the hydraulic fracture. We present a mathematical model of asymmetric hydrofracture growth based on relations between the solid‐phase stress and the fracture hydraulics. For single fracture and single injection point, the model has three parameters, hydraulic conductivities of the fracture wings, and normalised stress gradient and predicts the positions of the fracture tips as functions of time. The model is applied to a set of microseismic event locations that occurred during and after an injection process. Two different methods are suggested that make it possible to delineate the fracture tips from the set of microseismic events. This makes it possible to determine the model parameters and to check the agreement between the model prediction and the measured data. The comparison of the measured and modelled growth of fracture wings supports both the assumption of the non‐zero stress gradient and the existence of the post‐injection unilateral growth.

Wellbore Geomechanics of Extended Drilling Margin and Engineered Lost-Circulation Solutions

SummaryWellbore tensile failure is a known consequence of drilling with excessive mud weight, which can cause costly events of lost circulation. Despite the successful use of lost-circulation materials (LCMs) in treating lost-circulation events of the drilling operations, extensions of wellbore-stability models to the case of a fractured and LCM-treated wellbore have not been published. This paper presents an extension of the conventional wellbore-stability analysis to such circumstances. The proposed wellbore geomechanics solution revisits the criteria for breakdown of a fractured wellbore to identify an extended margin for the equivalent circulation density (ECD) of drilling. An analytical approach is taken to solve for the related multiscale and nonlinear problem of the three-way mechanical interaction between the wellbore, fracture wings, and LCM aggregate. The criteria for unstable propagation of existing near-wellbore fractures, together with those for initiating secondary fractures from the wellbore, are obtained. Results suggest that, in many circumstances, the occurrence of both incidents can be prevented, if the LCM blend is properly engineered to recover certain depositional and mechanical properties at downhole conditions. Under such optimal design conditions, the maximum ECD to which the breakdown limit of a permeable formation could be enhanced is predicted.

Evaluation of Fracture Asymmetry of Finite-Conductivity Fractured Wells

Nearly all commercial hydraulic fracture design models are based on the assumption that a single fracture is initiated and propagated identically and symmetrically about the wellbore, i.e., the fracture growth and proppant transport occurs symmetrically with respect to the well. However, asymmetrical fractures have been observed in hundreds of hydraulic fracturing treatments and reported to be a more realistic outcome of hydraulic fracturing. The asymmetry ratio (length of short fracture wing divided by length of long wing) influenced the production rate adversely. In the worst case, the production rate could be reduced to that of an unfractured well. Several authors observed asymmetrically propagated hydraulic fractures in which one wing could be ten times longer than the other. Most pressure transient analysis techniques of hydraulically fractured wells assume the fracture is symmetric about the well axis for the sake of simplicity in developing mathematical solution. This study extends the work by Rodriguez to evaluate fracture asymmetry of finite-conductivity fracture wells producing at a constant-rate. The analysis presented by Rodriguez only involves the slopes of the straight lines that characterize the bilinear, linear and radial flow from the conventional Cartesian and semilog plots of pressure drop versus time. This study also uses the Tiab’s direct synthesis (TDS) technique to analyze the linear and bilinear flow regimes in order to find the asymmetry factor of the fractured well. With the fracture conductivity estimated from the bilinear flow region, dimensionless fracture conductivity and the asymmetry ratio are calculated. A technique for estimating the fracture asymmetry ratio from a graph is presented. An equation relating the asymmetry ratio and dimensionless fracture conductivity is also presented. This equation assumes that the linear and/or bilinear flow regime is observed. However, using the TDS technique, the asymmetry ratio can be estimated even in the absence of bilinear or linear flow period. It is concluded that the relative position of the well in the fracture, i.e., the asymmetry condition, is an important consideration for the fracture characterization. A log-log plot of pressure derivative can be used to estimate the fracture asymmetry in a well intersected with a finite-conductivity asymmetric fracture. The analysis using pressure derivative plot does not necessarily require the radial flow period data to calculate the asymmetric factor.

The creation of an asymmetric hydraulic fracture as a result of driving stress gradients

SUMMARY Hydraulic fracture stimulation is frequently performed in hydrocarbon reservoirs and geothermal systems to increase the permeability of the rock formation. These hydraulic fractures are often mapped by hypocenters of induced microearthquakes. In some cases microseismicity exhibits asymmetry relative to the injection well, which can be interpreted by unequal conditions for fracture growth at opposite sides of the well or by observation effects. Here we investigate the role of the lateral change of the minimum compressive stress. We use a simple model to describe the relation among the lateral stress gradient, th e mean viscous pressure gradients in the fracture wings, the fracture geometry, and the net pressure in the fracture. Our model predicts a faster fracture growth in the direction of decrea sing stress and a limited growth in the opposite direction. We derive a simple relationship to estimate the lateral stress gradient from the injection pressure and the shape of the seismic hypocenter cloud. The model is tested by microseismic data obtained during stimulation of a Canyon Sands gas field in West Texas. Using a maximum likelihood method we fit the parameters of the asymmetric fracture model