Fluid Leakoff Research Articles

Water Leakoff During Gel Placement in Fractures: Extension to Oil-Saturated Porous Media

SummaryCrosslinked polymers extrude through fractures during placement of many conformance-improvement treatments, as well as during hydraulic fracturing. Dehydration of polymer gel during extrusion through fractures has often been observed and was extensively investigated during recent decades. Injection of highly viscous gel increases the pressure in a fracture, which promotes gel dehydration by fluid leakoff into the adjacent matrix. The present comprehension of gel behavior dictates that the rate of fluid leakoff will be controlled by the gel and fracture properties and, to a lesser extent, be affected by the properties of an adjacent porous medium. However, several experimental results, presented in this work, indicate that fluid leakoff deviates from expected behavior when oil is present in the fracture-adjacent matrix. We investigated fluid leakoff from chromium (Cr)(III)-acetate hydrolyzed polyacrylamide (HPAM) gels during extrusion through oil-saturated, fractured core plugs. The matrix properties were varied to evaluate the effect of pore size, permeability, and heterogeneity on gel dehydration and leakoff rate. A deviating leakoff behavior during gel propagation through fractured, oil-saturated core plugs was observed, associated with the formation of a capillary driven displacement front in the matrix. Magnetic resonance imaging (MRI) was used to monitor water leakoff in a fractured, oil-saturated, carbonate core plug and verified the position and existence of a stable displacement front. The use of MRI also identified the presence of wormholes in the gel, during and after gel placement, which supports gel behavior similar to the previously proposed Seright filter-cake model. An explanation is offered for when the matrix affects gel dehydration and is supported by imaging. Our results show that the properties of a reservoir rock might affect gel dehydration, which, in turn, strongly affects the depth of gel penetration into a fracture network and the gel strength during chase floods.

Consequences of rock layers and interfaces on hydraulic fracturing and well production of unconventional reservoirs

Hydraulic fracturing is a fundamental condition for economic production of hydrocarbons from unconventional reservoirs. Hydrocarbon production is proportional to the propped surface area that is in contact with the reservoir and remains connected to the wellbore. Yet, the propped surface area controlling production appears to be considerably smaller than the surface area created during pumping. Somehow hydraulic fractures are disconnected, truncated, and reduced during production. One important mechanism causing this segmentation is the shear displacement of weak interfaces between rock layers. Shear stresses are generated in response to abrupt changes in material properties and changes in bed orientation, in relation to the orientation of the existing principal stresses. If the layered rocks are strongly laterally heterogeneous, they provide a high potential for shear failures and fracture segmentation along the interfaces between layers. The induced shear stress and shear slip also depend on the current geologic structure and following in situ stress loading, the stress alteration and fluid leakoff during hydraulic fracturing, and the existence of wells. We conducted numerical simulations using the finite-element method on layered and discontinuous rocks, and specifically in organic-rich mudstones and carbonate sequences. Our work was part of a field study. Three different layered rock models were simulated and compared: laterally homogeneous, laterally heterogeneous, and strongly laterally heterogeneous. For the latter, the heterogeneity was introduced by randomly varying the elastic rock properties of each layer. Our results indicate that localized shear stresses develop along interfaces between materials with contrasting properties and along the wellbore walls. This includes the generation of localized shear in planes that were principal in the homogeneous model. It was also seen that rock shear and slip, along interfaces between layers, may occur when the planes of weakness are pressurized (e.g., during hydraulic fracturing).

Numerical modeling of hydraulic fracture propagation behaviors influenced by pre-existing injection and production wells

Hydraulic fracturing treatments are capable of enhancing the well production performance in low-porosity and low-permeability reservoirs because of the resulted improvement in communication between the formation and wellbore through created hydraulic fractures (HFs). In fact, not only the in-situ stress underground but also the pre-existing offset wells induced non-uniform pore pressure field will influence the HF propagation process. In this work, to investigate the HF propagation behaviors under the effects of adjacent production and injection wells, a new numerical model is developed within the framework of extended finite element method (XFEM) and cohesive zone method (CZM). The model can simultaneously simulate the HF initiation, propagation and reorientation, fracturing fluid flow and leakoff, formation fluid flow and rock deformation. Reliability of the new model is validated by comparing the numerically calculated fracture geometry with the experimental observation in the literature. The interesting and new results show that pore pressure field, stress field and fracture propagation speed can be altered around the pre-existing offset wells. Also, HF prefers to propagate toward injection wells when production and injection wells co-exist, and the fracture propagation trajectory will not be affected in the cases that only production or injection wells exist. The fracture will be shorter and wider when only injection wells exist or production and injection wells co-exist, while the pre-existence of only production wells leads to a longer and thinner HF. Moreover, a smaller pumping pressure can be applied to generate the HF when only production wells locate nearby, while a greater injection pressure is required to drive the HF forward when only injection wells pre-exist or injection and production wells co-exist. The obtained results provide new insights for understanding the fracture propagation behaviors in the field scale.

Acoustic Emission Response of Laboratory Hydraulic Fracturing in Layered Shale

Understanding the generation process of complex fracture network is essential for optimizing the hydraulic fracturing strategy in shale formations. In this study, laboratory fracturing was performed on shale specimens containing multiple bedding planes (BPs) combined with acoustic emission (AE) monitoring and computerized tomography scanning techniques. The injection pressure curve and the time dependency and hypocenter mechanisms of AE events in different stages were analyzed in detail. The relationship between AE spatial localization and hydraulically connected region were then further quantitatively discussed. Experimental results show that the characteristics of the pressure curve and AE response reflect well the hydraulic fracture (HF) growth behavior in layered shale. Shear events were detected around some weak BPs far away from the wellbore before the HF initiation. Stable injection pressure and a few AE events with low amplitude along the BP may indicate the stage of fluid leak-off. Numerous shear and tensile AE events and drastic pressure changes occur during the generation of a fracture network including breakdown in rock matrix and activation of multiple BPs. The shear instability of weak BPs caused by the stress perturbation during pressurization and HF growth tends to result in overestimation of the effective stimulated reservoir volume/hydraulically connected region.

Propagation of a Plane Strain Hydraulic Fracture With a Fluid Lag in Permeable Rock

Based on the KGD scheme, this paper investigates, with both analytical and numerical approaches, the propagation of a hydraulic fracture with a fluid lag in permeable rock. On the analytical aspect, the general form of normalized governing equations is first formulated to take into account both fluid lag and leak-off during the process of hydraulic fracturing. Then a new self-similar solution corresponding to the limiting case of zero dimensionless confining stress (T=0) and infinite dimensionless leak-off coefficient (L=∞) is obtained. A dimensionless parameter R is proposed to indicate the propagation regimes of hydraulic fracture in more general cases, where R is defined as the ratio of the two time-scales related to the dimensionless confining stress T and the dimensionless leak-off coefficient L. In addition, a robust finite element-based KGD model has been developed to simulate the transient process from L=0 to L=∞ under T=0, and the numerical solutions converge and agree well with the self-similar solution at T=0 and L=∞. More general processes from T=0 and L=0 to T=∞ and L=∞ for three different values of R are also simulated, which proves the effectiveness of the proposed dimensionless parameter R for indicating fracture regimes.

The effect of natural fracture on the fluid leak-off in hydraulic fracturing treatment

Abstract Fluid leak-off phenomenon plays a critical role in hydraulic fracturing operation. This phenomenon can be very impressive in successful operation of hydraulic fracturing. This operation is very complex in fractured reservoirs due to the reaction between induced fracture and natural fractures. In this study with the cohesive element method, the effect of presence of natural fracture on the magnitude of hydraulic fracturing fluid leak-off is investigated. First of all, cohesive element and extended finite element method methods are described. The fluid flow inside hydraulic fracture and the affecting parameters on leak-off of this fluid on adjacent environment are analyzed. Then, effects of natural fracture on hydraulic fracturing direction such as deviation, leak-off and the mutual influences (which includes the changes of stress regime around the natural fracture) and also changes in pore pressure are processed. The results indicate that presence of natural fracture will cause reduction in aperture of hydraulic fracture. This decrease will lead to extension of fluid lag and eventually delaying of leak-off phenomenon. However, this effect is negligible against the positive impact due to shear and normal displacement on increasing leak-off.

Hydraulic fracturing under high temperature and pressure conditions with micro CT applications: Geothermal energy from hot dry rocks

Hydraulic fracturing has been widely employed to enhance the permeability of tight geological formations including deep geothermal reservoirs. However, due to the complex in-situ stresses, high-temperature conditions and heterogeneity of the formations, hydraulic fracturing under deep geothermal conditions is poorly understood to date. The aim of the current study is, therefore, to investigate the effect of reservoir depth, temperature, and sample heterogeneity during hydraulic fracturing and the influences of rock micro-structure on fracture propagation. A series of hydraulic fracturing experiments was conducted on two Australian granite types under a wide range of confining pressures from 0 to 60 MPa and temperatures from room temperature to 300 °C simulating different geothermal environments. The corresponding micro-structural effects on the rock matrix were investigated employing high-resolution CT imaging using the IMBL facility of the Australian Synchrotron. According to the results, the breakdown pressure of reservoir rock linearly increases with reservoir depth (confining pressure). However, with increasing temperature breakdown pressure linearly decreases. This corresponds to the linear reduction of tensile strength measured by high-temperature Brazilian tensile tests. In addition, CT images showed that the injection of cold water into hot rock can result in a porous zone with porosity ranging from 2 to 3% close to the wellbore due to thermally-induced inter- and intra-crystalline cracks. In this condition, fluid leak-off is high and the measured fracture aperture of the main hydraulic fracture is relatively small. Further, fracture propagation paths and apertures are mainly controlled by the stress state and the heterogeneity of the rock matrix. It was found that fractures tend to propagate along preferential paths, mainly along grain boundaries and in large quartz and biotite minerals (grain size > 0.3 mm) and minerals with pre-existing micro-cracks.

Hydraulic fracturing with leakoff in a pressure-sensitive dual porosity medium

Hydraulic fracturing is a key method in the stimulation of shale gas reservoirs. Shale gas formations often contain natural fractures which are fluid-pressure sensitive and dilate in response to the inflation of the fracture, increasing fluid loss and slowing down and potentially prematurely arresting fracture propagation. Models typically assume 1-D single-porosity/permeability (Carter) leakoff perpendicular to the hydraulic fracture. However, the leakoff process in naturally fractured formations is considerably more complex. In this study, we present an hydraulic fracturing model based on the PKN-formalism which accommodates leakoff into a pressure-sensitive dual porosity medium. Proppant transport is accommodated by introducing empirical constitutive equations to determine the proppant distribution during the hydraulic fracturing treatment. The model is solved numerically and is validated against known small and large time asymptotic solutions. The model is capable of providing a rapid estimation of the morphology of hydraulic fractures in naturally fractured formations and the corresponding proppant distribution. The simulation results illustrate that the leakoff into a dual porosity medium, where fracture permeability is a strong function of applied fluid pressure, results in a reduced length of the propagating fracture due to the fugitive fluid leakoff from the fracture into the surrounding formation and that this in turn results in a reduced maximum width during the treatment. The ability to infuse proppants in fluid-driven fractures penetrating large distances from the injection wellbore is further limited by premature screen-out. This may compromise the ultimate efficiency of the final hydraulic fracture regarding gas recovery. Reduced propagation and premature screen-out are limited by low permeability and large spacing of the natural fractures. The presence of an existing network of natural fractures, including those adjacent to the hydraulic fracture that may become propped, aids in the recovery of the resource by reducing diffusion lengths of the hydrocarbon to the main fracture.

Impact of fluid compressibility for plane strain hydraulic fractures

Growing interest in hydraulic fracturing (HF) using super-critical CO2 (SC-CO2) calls into question the typical HF modeling assumption whereby the fluid compressibility is neglected. This paper models a plane strain HF driven by compressible fracturing fluid including the influence of viscous fluid flow, crack propagation through the host rock, and fluid leakoff into the host rock. The results show that, contrary to a reasonable initial hypothesis that compressibility would be important, in expected real world conditions the fluid compressibility has little impact on fracture propagation.

Coupled thermo-hydro-chemical modeling of fracturing-fluid leakoff in hydraulically fractured shale gas reservoirs

Once the low-temperature, high-pressure and low-salinity water contacts the shale matrix through the hydraulic fractures during the treatment of hydraulic fracturing, both mass and energy transfer occur due to the significant temperature, pressure, saturation and salinity gradients. Although, many leakoff models have been published, none of the models coupled the transient fluid flow modeling with heat transfer and chemical-potential equilibrium phenomena. In this paper, a coupled thermo-hydro-chemical (THC) model based on the derivation of non-isothermal chemical-potential equations from Gibbs’ free energy is presented to simulate fluid/heat flow behaviors during the leakoff process of hydraulic fracturing. The THC model takes into account a two-phase flow and a triple-porosity medium, which includes hydraulic fractures, organic and inorganic shale matrix. The simulation of fluid flow and leakoff with the THC model accounts for all the important mass and heat transfer processes occurring in fractured shale system, including fluid transport driven by convection, adsorption and diffusion, and heat transport driven by thermal convection and conductivity. The dynamic temperature, pressure, saturation and salt concentration profiles within fractures and shale matrix are calculated, revealing a multi-field coupled invasion region of fracturing-fluids during the treatment of hydraulic fracturing. In sensitivity analyses, cases with different initial reservoir temperature, pressure, saturation and brine salinity are considered. The impacts of the temperature, pressure, saturation and salinity gradients between the shale formation and the pumped fluids on the well injection and leakoff volumes during the treatment of hydraulic fracturing are investigated. Results show that although hydraulic pressure is the most factor which affects the fracturing-fluid leakoff behavior, the combination of chemical-osmosis, thermal-osmosis and capillarity still has a non-negligible influence on the fracturing-fluid leakoff. This study provides a better understanding of the mass and heat transport mechanism of water-based fracturing-fluids in shale gas reservoirs.

Finite element simulations of interactions between multiple hydraulic fractures in a poroelastic rock

A fully coupled three-dimensional finite-element model for hydraulic fracturing in permeable rocks is utilised to investigate the interaction between multiple simultaneous and sequential hydraulic fractures. Fractures are modelled as surface discontinuities within a three-dimensional matrix. This model simultaneously accounts for laminar flow within the fracture, Darcy flow within the rock matrix, poroelastic deformation of the rock, and the propagation of fractures using a linear elastic fracture mechanics framework. The leakoff of fracturing fluid into the surrounding rocks is defined as a function of the pressure gradient at the fracture surface, the fluid viscosity, and the matrix permeability. The coupled equations are solved numerically using the finite element method. Quadratic tetrahedral and triangle elements are used for spatial discretisation of volumes and surfaces, respectively. The model is validated against various analytical solutions for plane-strain and penny-shaped hydraulic fractures. Several cases of simultaneous fracturing of multiple hydraulic fractures are simulated in which the effects of the various parameters (the in situ stresses, the distance between fractures, the permeability of the matrix, the Biot poroelastic coefficient, and the number of the fractures in a group) are investigated. The results show that the stress induced by the opening of the fractures, and the stress induced by the fluid leakoff, each have the effect of locally altering the magnitudes and orientations of the principal stresses, hence altering the propagation direction of the fractures. Opening of a fracture induces excessive compression (also known as the “stress shadow”) that causes adjacent fractures to curve away from each other. This excessive compression competes against the differential in situ stresses, which tend to cause the fracture to grow in the plane normal to the minimum in situ stress. The stress shadow effect is reduced by increasing the distance between fractures, and is increased by increasing the leakoff, which may be due to increased permeability of the rock, or an increase in the Biot coefficient.

Tiltmeter Mapping of Measured Nonsymmetric Hydraulic-Fracture Growth in a Conglomerate/Sandstone Formation Using the Implicit Level-Set Algorithm and the Extended Kalman Filter

SummaryA novel method to map asymmetric hydraulic-fracture propagation using tiltmeter measurements is presented. Hydraulic fracturing is primarily used for oil-and-gas well stimulation, and is also applied to precondition rock before mining. The geometry of the developing fracture is often remotely monitored with tiltmeters—instruments that are able to remotely measure the fracture-induced deformations. However, conventional analysis of tiltmeter data is limited to determining the fracture orientation and volume. The objective of this work is to detect asymmetric fracture growth during a hydraulic-fracturing treatment, which will yield height-growth information for vertical fracture growth and horizontal asymmetry for lateral fracture growth or detect low preconditioning-treatment efficiency in mining. The technique proposed here uses the extended Kalman filter (EKF) to assimilate tilt data into a hydraulic-fracture model to track the geometry of the fracture front. The EKF uses the implicit level set algorithm (ILSA) as the dynamic model to locate the boundary of the fracture by solving the coupled fluid-flow/fracture-propagation equations, and uses the Okada half-space solution as the observation model (forward model) to relate the fracture geometry to the measured tilts. The 3D fracture model uses the Okada analytical expressions for the displacements and tilts caused by piecewise constant-displacement discontinuity elements to discretize the fracture area. The proposed technique is first validated by a numerical example in which synthetic tilt data are generated by assuming a confining-stress gradient to generate asymmetric fracture growth. The inversion is carried in a two-step process in which the fracture dip and dip direction are first obtained with an elliptical fracture-forward model, and then the ILSA-EKF model is used to obtain the fracture footprint by fixing the dip and dip direction to the values obtained in the first step. Finally, the ILSA-EKF scheme is used to predict the fracture width and geometry evolution from real field data, which are compared with intersection data obtained by temperature and pressure monitoring in offset boreholes. The results show that the procedure is able to satisfactorily capture fracture growth and asymmetry even though the field data contain significant noise, the tiltmeters are relatively far from the fracture, and the dynamic model contains significant “unmodeled dynamics” such as stress anisotropy, material heterogeneity, fluid leakoff into the formation, and other physical processes that have not been explicitly accounted for in the dynamic ILSA model. However, all the physical processes that affect the tilt signal are incorporated by the EKF when the tilt measurements are used to obtain the maximum likelihood estimates of the fracture widths and geometry.

Minimize Formation Damage in Water-Sensitive Montney Formation With Energized Fracturing Fluid

Summary Slickwater has been widely used for hydraulic fracturing because it is inexpensive and able to carry proppants into the fracture (Schein 2005; Palisch et al. 2010). This fluid, however, is unsuitable for water-sensitive formations, such as the Montney formation. This is because water saturation around the fractures increases, and the clay swells when water leaks into the matrix, both of which hinder the flow of natural gas from the matrix into the fractures. N2- or CO2-energized water-based fracturing fluids have been widely used in water-sensitive formations because they can minimize fluid leakoff during fracturing and help achieve higher-load fluid recovery during flowback (Burke and Nevison 2011; Barati and Liang 2014). In this paper, multiphase numerical simulations are applied to study the formation-damage mitigation in the Montney tight reservoir with energized fracturing fluid. A simulation model is built and history-matched with flowback and early production data gathered from a typical Montney tight gas well. The behavior of the multiphase fluid leakoff and flowback is studied. Sensitivities of the foam quality of the fracturing fluid on the load fluid recovery are analyzed, as is the well productivity after stimulation. Statistical analysis to study the performance of energized fracturing in the water-sensitive Montney formation is conducted on the stimulation and production data of more than 5,000 Montney wells. We found that multiphase fracturing fluid has less dynamic fluid leakoff compared with that of a single-phase fracturing fluid (i.e., water). The major fluid leakoff occurs during the static leakoff period between the end of the stimulation processes and the start of the flowback. The gas phase penetrates deeper and faster into the reservoir matrix compared with the liquid phase, which contributes to the increased flowback volume of the fracturing fluid. Formation damage caused by fracturing-fluid leakoff can affect both early and long-term production. In addition, N2 foam leads to the highest-load fluid recovery in the Montney formation, which is 1.6 times that of CO2 foam. This work provides critical insights into understanding the performance of using energized fracturing fluid to mitigate formation damage in tight formations.

A fully coupled three-dimensional hydraulic fracture model to investigate the impact of formation rock mechanical properties and operational parameters on hydraulic fracture opening using cohesive elements method

Hydraulic fracturing operation success is critically dependent on pre-operation fracture geometry analysis. Meantime, hydraulic fracture opening determination is crucial because it deals with maintaining sufficient aperture and efficient communication pathways to accomplish proppant placement and avoid screen-outs or proppant bridging. It is well understood that, to efficiently estimate the hydraulic fracture opening, a thorough understanding of the impact of rock mechanical properties as well as operational parameters such as injection fluid viscosity and leak-off are essential. In this study, a three-dimensional model has been developed for parametric study of fracture stiffness, formation elastic modulus, formation Poisson’s ratio, tensile strength of the rock, fracturing fluid viscosity and leak-off, and their influences on hydraulic fracture opening. Cohesive elements with traction–separation law have been applied to simulate the fracturing process in a fluid-solid coupling model. The maximum nominal stress criterion has been selected for initiation of damage in the cohesive elements. The results revealed that any change in influential rock mechanical properties as well as operational parameters would significantly lead to increasing or decreasing the hydraulic fracture opening. It was observed from the controllable HF parameters including fracturing fluid viscosity and leak-off, by increasing fracturing fluid viscosity from 10−3 to 10 Pa.s, fracture width has been moderately increased from 8.83 to 13.3 mm; on the other hand, by reducing leak-off coefficient as a polymer-dependent HF parameter from 5 × 10−9 to 5 × 10−11 m/kPa.s, fracture width has been gradually risen from 7.27 to 11.52 mm. In addition, all the uncontrollable rock mechanical parameters such as fracture stiffness, Young’s modulus, Poisson’s ratio, and tensile strength have steeply increased or decreased the hydraulic fracture opening and consequently, all of their analysis will be discussed in detail in this research. The results from this study can be applied to hydraulic fracturing jobs in different conditions of fracture stiffness, formation elastic modulus, formation Poisson’s ratio, tensile strength of the rock, fracturing fluid viscosity, and leak-off.

An approximate solution for a plane strain hydraulic fracture that accounts for fracture toughness, fluid viscosity, and leak-off

The goal of this paper is to develop an approximate solution for a propagating plane strain hydraulic fracture, whose behavior is determined by a combined interplay of fluid viscosity, fracture toughness, and fluid leak-off. The approximation is constructed by assuming that the fracture behavior is primarily determined by the three-process (viscosity, toughness, and leak-off) multiscale tip asymptotics and the global fluid volume balance. First, the limiting regimes of propagation of the solution are considered, that can be reduced to an explicit form. Thereafter, applicability regions of the limiting solutions are investigated and transitions from one limiting solution to another are analyzed. To quantify the error of the constructed approximate solution, its predictions are compared to a reference numerical solution. Results indicate that the approximation is able to predict hydraulic fracture parameters for all limiting and transition regimes with an error of under one percent. Consequently, this development can be used to obtain a rapid solution for a plane strain hydraulic fracture with leak-off, which can be used for quick estimations of fracture geometry or as a reference solution to evaluate accuracy of more advanced hydraulic fracture simulators.

Fracturing Fluid Leak-off for Deep Volcanic Rock in Zhungeer Basin: Mechanism and Control Method

The deep volcanic reservoir in Zhungeer Basin is buried in over 4000m depth, which is characterized by complex lithology (breccia, andesite, basalt, etc.), high elastic modulus and massive natural fractures. During hydraulic fracturing, hydraulic fracture will propagate and natural fractures will be triggered by the increasing net pressure. However, the extension of fractures, especially natural fractures, would aggravate the leak-off effect of fracturing fluid, and consequently decrease the fracturing success rate. 4 out of 12 fracturing wells in the field have failed to add enough proppants due to fluid loss. In order to increase the success rate and efficiency of hydraulic fracturing for deep volcanic reservoir, based on theoretical and experimental method, the mechanism of fracturing fluid leak-off is deeply studied. We propose a dualistic proppant scheme and employ the fluid loss reducer to control the fluid leak-off in macro-fractures and micro-fractures respectively. The proposed technique remarkably improved the success rate in deep volcanic rock fracturing. It bears important theoretical value and practical significance to improve the hydraulic fracturing design for deep volcanic reservoir.

FRACTURING FLUID LEAKOFF BEHAVIOR IN NATURAL FRACTURES: EFFECTS OF FLUID RHEOLOGY, NATURAL FRACTURE DEFORMABILITY, AND HYDRAULIC FRACTURE PROPAGATION

This study developed a coupled model for the fracturing fluid loss into natural fractures during a hydraulic fracturing treatment. The model considers a non-Newtonian fracturing fluid, the influence of hydraulic fracture, and the fluid exchange between hydraulic and natural fractures. A semianalytical solution is proposed to solve the coupled model, which demonstrates reliable results through validation study. Parametric studies indicate that increasing the fracturing fluid viscosity can effectively reduce its leakoff at a low viscosity level. While at a high level, further enlarging fluid viscosity may not lead to better control of leakoff. In addition, larger deformability of reservoir rock leads to a faster pressure diffusion and a greater fluid leakoff. Also, the pressure profile inside a fracture takes a concave shape when the deformation of a natural fracture is considered. Moreover, it is found that when a large number of natural fractures open at the same time, fluid leakoff can cause an immediate reduction in the hydraulic fracture width and even screen-out. Therefore, to reduce the operation risks of hydraulic fracturing, the pump rate and fluid rheology must be carefully designed based on the properties of natural fractures in reservoirs.

An approximate solution for a penny-shaped hydraulic fracture that accounts for fracture toughness, fluid viscosity and leak-off.

This paper develops a closed-form approximate solution for a penny-shaped hydraulic fracture whose behaviour is determined by an interplay of three competing physical processes that are associated with fluid viscosity, fracture toughness and fluid leak-off. The primary assumption that permits one to construct the solution is that the fracture behaviour is mainly determined by the three-process multiscale tip asymptotics and the global fluid volume balance. First, the developed approximation is compared with the existing solutions for all limiting regimes of propagation. Then, a solution map, which indicates applicability regions of the limiting solutions, is constructed. It is also shown that the constructed approximation accurately captures the scaling that is associated with the transition from any one limiting solution to another. The developed approximation is tested against a reference numerical solution, showing that accuracy of the fracture width and radius predictions lie within a fraction of a per cent for a wide range of parameters. As a result, the constructed approximation provides a rapid solution for a penny-shaped hydraulic fracture, which can be used for quick fracture design calculations or as a reference solution to evaluate accuracy of various hydraulic fracture simulators.

Positron-Emission Tomography Offers New Insight Into Wormhole Formation

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 180051, “New Insight Into Wormhole Formation in Polymer Gel During Water Chase Floods Using Positron-Emission Tomography,” by B. Brattekås, University of Stavanger; M. Steinsbø, A. Graue, M.A. Fernø, and H. Espedal, University of Bergen; and R.S. Seright, New Mexico Petroleum Recovery Research Center, prepared for the 2016 SPE Bergen One-Day Seminar, Bergen, Norway, 20 April. The paper has not been peer reviewed. Polymer gel is frequently used for conformance control in fractured reservoirs, where it is injected to reside in fractures or high-permeability streaks to reduce conductivity. Polymer-gel behavior is often studied in corefloods, where differential pressure and effluents from fracture and matrix outlets give information about gel deposition during placement and flow paths during chase floods. The work presented in this paper uses complementary positron-emission-tomography (PET)/computed-tomography (CT) imaging to quantify the behavior and blocking capacity of gel during chase waterflooding. Introduction Channeling of injected fluids through a highly permeable fracture network, and the following early fluid breakthrough, may be mitigated by placing a highly viscous polymer gel in the fracture. With polymer gel in place, higher differential pressures may be achieved during chase floods, which can contribute to increased sweep efficiency in the porous matrix adjacent to the fracture network. A polymer gel is formed when a gelant solution is exposed to elevated temperature for a given time, known as the gelation time. Previous work has investigated how the gel state during placement (gel or gelant) influenced the gel behavior during chase floods. The complete paper provides a detailed discussion of previous models for fluid leakoff. In this work, the authors study the extrusion of formed polymer gel through fractures, and its resistance to pressure during subsequent waterfloods. PET imaging is based on the decay of positron-emitting radionuclides. In this work, PET was used to visualize flow of radioactive water through a gel-filled fracture, to augment global measurements, and to increase the understanding of filter-cake formation during formed-gel placement and wormhole formation during chase floods. A discussion of the experimental setup, including limestone- and sandstone-core-plug preparation, polymer-gel placement, the chase-flood procedure, and the PET-imaging process, is provided in the complete paper.

A stabilized extended finite element framework for hydraulic fracturing simulations

SummaryWe present a stabilized extended finite element formulation to simulate the hydraulic fracturing process in an elasto‐plastic medium. The fracture propagation process is governed by a cohesive fracture model, where a trilinear traction‐separation law is used to describe normal contact, cohesion and strength softening on the fracture face. Fluid flow inside the fracture channel is governed by the lubrication equation, and the flow rate is related to the fluid pressure gradient by the ‘cubic’ law. Fluid leak off happens only in the normal direction and is assumed to be governed by the Carter's leak‐off model. We propose a ‘local’ U‐P (displacement‐pressure) formulation to discretize the fluid‐solid coupled system, where volume shape functions are used to interpolate the fluid pressure field on the fracture face. The ‘local’ U‐P approach is compatible with the extended finite element framework, and a separate mesh is not required to describe the fluid flow. The coupled system of equations is solved iteratively by the standard Newton‐Raphson method. We identify instability issues associated with the fluid flow inside the fracture channel, and use the polynomial pressure projection method to reduce the pressure oscillations resulting from the instability. Numerical examples demonstrate that the proposed framework is effective in modeling 3D hydraulic fracture propagation. Copyright © 2016 John Wiley & Sons, Ltd.