Fracturing In Unconventional Reservoirs Research Articles

Optimization of Spacing and Penetration Ratio for Infinite-Conductivity Fractures in Unconventional Reservoirs: A Section-Based Approach

Summary In this paper, we consider the development plan of shale gas or tight oil with multiple multistage fractured laterals in a large square drainage area that we call a “section” (usually 640 acres in the US). We propose a convenient section-based optimization of the fracture array with two integer variables, the number of columns (horizontal laterals) and rows (fractures created in a lateral), to provide some general statements regarding spacing of wells and fractures. The approach is dependent on a reliable and efficient productivity-index (PI) calculation for the boundary-dominated state (BDS). The dimensionless PI is obtained by solving a time-independent eigenvalue problem by use of the finite-element method (FEM) combined with the Richardson extrapolation. The results of the case study demonstrate two decisive factors: the dimensionless total fracture length, related to the total amount of proppant and fracturing fluid available for the section, and the feasible range of actual fracture half-lengths, related to current fracturing-technology limitations. Under the constraint of dimensionless total fracture length, increasing the number of columns (horizontal laterals) increases the total PI but with only diminishing returns, whereas the optimal fracture-penetration ratio decreases somewhat, but is still near unity. When adding the technological constraint of a limited range of fracture half-lengths that can be routinely and reliably created, only a few choices remain admissible, and the optimal decision can be easily made. These general statements for the ideal homogeneous and isotropic formation can serve as a reference in the more-detailed optimization works. In other words, we offer a first-pass method for decision making in early stages when detailed inputs are not yet available. The information derived from the section-based optimization method and the efficient and reliable algorithm for PI calculation should help the design of multistage fracturing in shale-gas or ultralow-permeability oil formations.

A Laplace-Domain Hybrid Model for Representing Flow Behavior of Multifractured Horizontal Wells Communicating Through Secondary Fractures in Unconventional Reservoirs

Summary In a multiwell pad, the chance of interwell communication increases because of the creation of primary and secondary fractures during hydraulic-fracture stimulation. The flow behavior associated with communicating wells is significantly different from that of a single isolated well, because of interplay of flow caused by the interconnected fractures, complex connections, and multiple production conditions. The main purpose of this paper is to develop a rigorous and efficient flow model and quantify flow characteristics of multiple pad wells communicating through primary and secondary fractures. In the model, matrix and primary- and secondary-fracture flows are captured. Fractures are explicitly represented by discrete segments. The Laplace-transform finite-difference (LTFD) method is used to numerically model fracture flow, with sufficient flexibility to consider arbitrary fracture geometries and fracture-conductivity distributions. The analytical matrix-flow model, derived with the line-source function in the Laplace domain, is dynamically coupled with the fracture-flow model, by imposing the continuity of pressure and flux on the fracture surface. Thus, a hybrid model in the Laplace domain is constructed. The main advantage of the solution occurring in Laplace domain is that computations can be performed at predetermined, discrete times, and with grids only for fractures. Thus, stability and convergence problems caused by time discretization are avoided, and the burden of gridding and computation is decreased without loss of important fracture characteristics. The model is validated through comparison with a fully numerical simulator and a semi-analytical model. Detailed flow-regime analysis reveals that pressure interference caused by communication significantly alters the flow signature compared with single (isolated) wells. Before interference, the communicating wells behave as single isolated wells, and will exhibit a fracture linear-flow period and possibly even a matrix linear-flow period. After interference, the flow behavior of the system will vary largely with different production strategies. When the communicating wells all operate under the constant-rate condition, the transient responses of the wells will gradually merge to develop another matrix linear-flow period. If the wells are operated under the constant-bottomhole-pressure (BHP) conditions, the response deviation caused by interference will increase with production; therefore, one of the wells will undergo a rate loss. The results of a sensitivity analysis for a two-well system demonstrate that the time to well interference is primarily determined by secondary-fracture conductivity, number of connections, and communicating-well operating conditions. With larger contrasts in these properties, interference time is accelerated. However, for different production strategies, the effects on the flow behavior after interference are variable.

Rate-independent fracture toughness of gray and black kerogen-rich shales

The objective of this investigation is to characterize the influence of the loading rate, scratch speed, mineralogy, morphology, anisotropy, and total organic content on the scratch toughness of organic-rich shale. We focus our study on a gray shale, Toarcian shale (Paris basin, France) and a black shale, Niobrara shale (northeastern Colorado, USA). Microscopic scratch tests are performed for varying scratch speeds and loading rates. We consider several orientations for scratch testing. For all gas shale specimens, the scratch toughness is found to increase with increasing scratch speed. In the asymptotic regime of high speeds, there is a convergence toward a single constant value irrespective of the loading rate. To understand this evolution of the scratch toughness, a nonlinear fracture mechanics model is built that integrates fracture dissipation with the various forms of viscous processes. In particular, a coupling is shown between the fracture energy and the viscoelastic characteristics. An inverse approach which combines scratch and indentation testing makes it possible to represent all tests in a single curve and retrieve the rate-independent fracture toughness of kerogen-rich shale materials. The presence of organic matter drastically alters the creep and fracture properties at the microscopic length-scale. The fracture behavior is anisotropic with the divider orientation yielding the highest fracture toughness value and the short transverse orientation yielding the lowest fracture toughness. Elucidating the fracture-composition-morphology relationships in organic-rich shale will promote advances in science and engineering for energy-related applications such as hydraulic fracturing in unconventional reservoirs or $$\hbox {CO}_2$$ sequestration in depleted reservoirs.

Transient responses of multifractured systems with discrete secondary fractures in unconventional reservoirs

This paper provides a semi-analytical model to analyze the transient responses of multifractured systems with discrete secondary fractures in unconventional reservoirs. The model idealizes the stimulated reservoir volume as two regions: a primary hydraulic-fracture and discrete secondary fractures. Transient pressure and derivative responses are obtained by coupling an analytical model for matrix flow and a numerical model for fracture flow. This approach can consider the fracture characteristics in detail. For example, the discrete secondary fractures may interconnect the primary hydraulic-fracture with different inclination, nonuniform fracture spacing and varying conductivity. The semi-analytical model was verified in comparison with the results of a fully numerical simulation model.Transient flow behavior of the system was analyzed in detail. The study has shown that a multifractured system with discrete secondary fractures may exhibit four flow regimes: bilinear flow, fluid feed flow, matrix linear flow and pseudosteady-state flow. In the fluid feed flow period, the secondary fractures act as supply sources to feed the primary hydraulic-fracture to generate a dip on the type curves. Local solutions for the matrix linear flow are similar to that for a finite conductivity vertical fracture and can be correlated with the ratio of the total length of the secondary fractures to that of the primary hydraulic-fracture and an intercept term. With the increasing of number of secondary fracture, the ending time of the bilinear flow will be advanced and the fluid feed flow period will come earlier. The dimensionless secondary fracture length determines the slope of the straight line of the matrix linear flow on square-root-dimensionless-time plot. As the secondary fracture inclination decreases, the duration of the matrix linear flow period is shortened and the beginning time of the pseudosteady-state flow period is delayed. In addition, the secondary fracture conductivity affects the depth of the dip and the beginning time of the matrix linear flow period. However, the influence is not appreciable on the log/log graph.

Fracture Modeling Using a Constructed Discrete Fracture Network From Seismic Data

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 179130, “Calibrated Complex Fracture Modeling Using a Constructed Discrete Fracture Network From Seismic Data in the Avalon Shale, New Mexico,” by Foluke Ajisafe, Manoj Thachaparambil, Donald Lee, Ben Flack, Kim Hemsley, Efe Ejofodomi, and Christopher Taylor, Schlumberger, prepared for the 2016 SPE Hydraulic Fracturing Technology Conference, The Woodlands, Texas, USA, 9–11 February. The paper has not been peer reviewed. The objective of this study is to validate the concept of using a seismically derived discrete fracture network (DFN) calibrated with borehole measurements, for complex-hydraulic-fracture modeling. This study was applied successfully on a two-well horizontal pad in the Avalon Shale located in the Delaware Basin, New Mexico. The work flow presented in this paper shows the successful application of seismic data in creating DFNs required to model hydraulic fractures in unconventional reservoirs. Introduction In the past, hydraulic-fracture modeling was limited to planar models for conventional reservoirs, with the absence of natural fractures. In unconventional reservoirs, planar models are highly limited in properly simulating complex fracture geometries. In recent years, a state-of-the-art complex- fracture-network model, also known as an unconventional fracture model (UFM), was developed. The model simulates the fracture propagation, rock deformation, and fluid flow in the complex fracture network created during a treatment. A key difference between the UFM and the conventional planar-fracture model is the ability to simulate the interaction of hydraulic fractures with pre-existing natural fractures. In shale plays, conventional DFN models are built out of 1D fracture-dip interpretation from a borehole-image log or from core in the same or a nearby well. However, because the hydraulic fractures created during a stimulation treatment usually extend hundreds of feet away from the wellbore, it is important to characterize and understand the natural fractures away from the wellbore. Therefore, a more-accurate DFN model than the simple conventional model is crucial in unconventional plays for optimizing well spacing and stimulation design to ultimately achieve maximum effective drainage while maximizing returns. In this study, the authors use an established work flow for extracting seismic-scale fracture networks and extending their population properties to model corresponding subseismic fractures that are critical to understanding and calibrating complex-hydraulic-fracture geometry created during stimulation. Geology The Avalon unconventional shale play consists of siltstone, limestone, clay, chert, and organics. It can be subdivided into three zones: upper, middle, and lower. In the past, the Avalon shale has been exploited by vertical drilling, but recently, horizontal drilling has been the trend to fully exploit this unconventional play.

Integrated simulation of multi-stage hydraulic fracturing in unconventional reservoirs

In recent years, the multi-stage hydraulic fracturing technology has been widely applied to unconventional reservoirs. In order to optimize the stimulation performance and achieve economic production rates, the underlying physics and the impacts of different designing parameters must be quantitatively understood prior to the operations. Although many numerical models have been developed for this purpose, few are capable of properly taking into account the interplay of different mechanisms, such as fluid flow in the horizontal wells, fracture propagation, and proppant transport.A novel 3D thermal-hydro-mechanical model entitled UFrac is developed in this paper. This model integrates the various mechanisms to capture the interactions among wellbores, fractures and reservoir rocks. The fluid flow inside the wells and the fractures is simulated with the finite volume method (FVM), the elastic deformations of rock mass are calculated with the 3D displacement discontinuity method (DDM), and fracture propagation is simulated with the fixed grid method. The UFrac model is capable of simulating the combined effects of multiple fracturing operation parameters, elastic interaction between fractures, and temperature redistribution induced by flow exchange.By using the UFrac model, we investigate several key problems in hydraulic fracturing such as fracture height growth, perforation spacing optimization, and thermal effect on proppant placement. Important conclusions are drawn from the simulation results. The strength of stress interaction is found to be related to the fracture geometries. Stress shadow effect does not only affect the flow partitioning and fracture size distribution, but also influence the proppant transport. Friction loss in the wellbore can affect the decisions on spacing optimization. Moving inner fractures closer to the heel of the wells would be beneficial for fracture propagation balancing. Fluid viscosity loss due to heating from the surrounding formations results in longer but narrower fractures and faster settling of proppant. The modeling of proppant distribution aids in better characterization of the fracture conductivity, thus provides more reliable prediction of the well productivity.

Efficient evaluation of gas recovery enhancement by hydraulic fracturing in unconventional reservoirs

Hydraulic fracturing is an important approach to improve production rate in unconventional gas reservoirs. A proper evaluation of the effectiveness of fracturing process is essential for designing and optimizing future stimulation operations. The recent advances in diagnostic techniques and mineback observations provide evidences of the existence of complex fracture networks. Decline curve analysis also highlights the impact of pre-existing fractures on production. In this paper, we propose a hybrid model which is capable of simulating the multi-scale complex fracture network in a very efficient way.A uniformly global upscaling technique is used to get reliable calculation of transmissibilities between sim-grids of different media without introducing artificial parameters such as shape factors. In the upscaling framework, a high-resolution discrete fracture model of the complex fracture network is firstly built as the reference model. Then a coarse unstructured grid conforming to primary fractures is generated based on this fine scale model and serves as the simulation grid. In the coarse model, large scale fractures are treated explicit like conventional discrete fracture models, while relatively small-scale fractures are upscaled into dual porosity grids by global upscaling procedures.A synthetic case and a field scale problem are designed and implemented to validate and illustrate the capability of the proposed method. The results show that our model can save considerable computation time while preserve the accuracy of simulation. This model can serve as a reliable tool to fast evaluate different plans for enhanced gas recovery, especially in the case when multiple realizations are required for uncertainty analysis.

Three-dimensional investigation of multiple stage hydraulic fracturing in unconventional reservoirs

Production efficiency from low permeability shale reservoirs demands promoting techniques including horizontal well drilling and multiple hydraulic fracture stimulation. What significantly affects the fracture patterns and associated geometries is the stress field changes induced by pre-existing or simultaneous fractures, depending on proposed hydraulic fracturing scenarios. Devising a reliable and robust simulation tool for hydro-mechanical modeling of hydraulic fracturing is imperative inasmuch as an appropriate fracturing job in a porous medium cannot be extended to another owing to various characteristics and limited access to the field data acquisition. In order to present a numerical technique, which is capable of capturing the non-planar hydraulically fluid-driven crack propagation with unpredictable path, in one hand, and tackling the feasible emergence of multiple cohesive cracks in a porous medium with fracture process zone at the crack tip, on the other hand, the Cohesive segments method in combination with Phantom Node Method, called CPNM herein, is established to simulate 3-D non-planar hydraulically driven fracture problem in a quasi-brittle shale medium. The present simulation fully couple fracturing fluid flow inside the crack with poro-elasticity in porous formation and continuum-based leak-off on the crack surfaces, and capture the fracture process zone at the fracture tip in quasi-brittle shale. In this paper, two different key scenarios including sequentially and simultaneously multiple hydraulic fracturing in a quasi-brittle shale multi-layer are investigated by using CPNM. The interesting and new results show that later stages in sequentially hydraulic fracturing mainly secure larger values of fracture opening than that of simultaneously hydraulic fracturing, which can be attributed to the effect of stress interactions of fractures on each other. Detailed parametric studies shed new light on the impacts of pre-existing or simultaneous fluid-driven fractures on the pore pressure of the formation, crack propagation pattern, von Mises stresses, fracture opening, leak-off flow rate, and fracturing fluid pressure.

Quantitative evaluation of rock brittleness and fracability based on elastic-wave velocity variation around borehole

Abstract Brittleness and fracability are two important rock properties in hydraulic fracturing of unconventional reservoirs. Based on the variation of compressional and shear velocity around borehole using acoustic measurement, an effective technique is developed to estimate these parameters to guide reservoir-fracturing. During drilling, when the rock is broken, a significant amount of drilling induced cracks will occur in the formation around the borehole, reducing elastic wave velocity around borehole and causing the wave velocity variation away from borehole. The radial variation of compressional and shear velocities of formation rocks surrounding a borehole were respectively obtained from P-wave travel time tomography and dipole shear-wave dispersion inversion. By integrating the two variation profiles along the radial direction, the brittleness-fracability index is obtained to estimate the brittleness and fracability of formation rocks. The index shows fairly good consistency and correlation with rock brittleness and fracability, which demonstrates the practicability and effectiveness of the proposed approach. Well log data analysis examples are presented to demonstrate the effectiveness of our technique.

Hydraulic fracture propagation direction during volume fracturing in unconventional reservoirs

Abstract Creating an artificial fracture network by hydraulic fracturing plays the most important role in unconventional oil and gas development. The propagation direction of a fracture is the base to understand the mechanism of forming a fracture network. For size limitation, the fracture propagation direction has not been well studied in labs. In this paper, a comprehensive numerical model is developed to study the fracture propagation direction during volume fracturing of unconventional reservoirs. The model is based on elastic and fracturing mechanics of a rock, as well as the maximum circumferential stress criterion and boundary element method. Simulated results prove that, the propagation direction of a hydraulic fracture is affected by formation in-situ stresses, hydraulic pressure in the fracture and the initial azimuth of the fracture. An H factor is proposed to evaluate the combined effect of those factors, and proved mathematically and numerically that it is a major factor controlling a fracture propagation direction. Fractures will follow the same propagation path if the H factor keeps constant for different stresses and pressure combination. A fracture will follow the direction of the in-situ maximum principal stress as the applied internal hydraulic pressure in the fracture is less than the maximum stress, otherwise, the fracture will try to follow its initial azimuth and yield a propagation direction path between its initial azimuth and the direction of the in-situ maximum principal stress. The work is helpful in understanding the forming process of a complex fracture network during hydraulic fracturing in unconventional reservoirs. The H factor is useful in reducing both lab test and numerical simulation times, making lab tests of fracture extension at high stresses and pressure viable.

Multi-phase fracturing fluid leakoff model for fractured reservoir using extended finite element method

Fracturing fluid leakoff into natural fractures determines the propagation of a hydraulically-driven fracture, especially for slick-water fracturing in unconventional reservoirs. This paper proposes a multi-phase model of fluid flow in a fractured porous medium using the extended finite element method (XFEM), and investigates the effects of pre-existing natural fissures on fracturing fluid leakoff. This model introduces an absolute value of signed distance function and appropriate branch functions to refine the local discontinuities in the modeled pressure derivatives across the fractures. This local refinement is independent of the matching grid and is easily incorporated into XFEM-based stress analysis for crack propagation modeling. A numerical example is provided, in which the cumulative leakoff volume versus exposure time behavior for a single natural fracture with different intersection angles with a hydraulic fracture is investigated, along with that of a single non-intersected natural fracture at different distances from a hydraulic fracture. In addition, the leakoff behavior into a pre-existing fracture is compared with that into matrix rock. These comparisons indicate that the cumulative leakoff volume is linearly proportional to the square root of the leakoff time for matrix rock unaffected by fractures, while it is linearly proportional to the leakoff time in the case of non-intersected fractures.

Optimization of hydraulic fracturing design under spatially variable shale fracability

Abstract Current hydraulic fracturing designs are based on equal fracture intervals (spacing) along horizontal wells. Typical fracture spacing ranges from 50 to 600 feet while the fracture half-lengths normally vary between 100 and 600 feet. Symmetric spacing designs assume homogeneous shale mechanical property distributions, e.g. rock brittleness or fracability, which may not be the case in many shale plays. Fracability of the shale rock is an important property that controls the efficiency of the fracturing process. Therefore, the heterogeneity in shale fracability can have an important impact on the design and optimization of the hydraulic fracturing process. In particular, the optimal number, location, and length of the fractures can depend on rock fracability distribution. In this paper, we develop an optimization approach for hydraulic fracturing design under geospatial variability in shale fracability and investigate several aspects of the proposed fracture design optimization approach. In particular, we optimize the hydraulic fracturing design by implementing a variant of the Simultaneous Perturbation Stochastic Approximation algorithm to maximize the net present value of the shale asset, including the cost of fracturing and the revenue from gas production. The optimization framework provides a systematic design approach for hydraulic fracturing of unconventional reservoirs and can be applied to improve production efficiency and reduce the cost and environmental impact of hydraulic fracturing. We demonstrate the effectiveness and suitability of the proposed method using a series of numerical experiments in shale gas development.

Characterizing hydraulic fractures in shale gas reservoirs using transient pressure tests

Abstract Hydraulic fracturing combined with horizontal drilling has been the technology that makes it possible to economically produce natural gas from unconventional shale gas or tight gas reservoirs. Hydraulic fracturing operations, in particular, multistage fracturing treatments along with horizontal wells in unconventional formations create complex fracture geometries or networks, which are difficult to characterize. The traditional analysis using a single vertical or horizontal fracture concept may be no longer applicable. Knowledge of these created fracture properties, such as their spatial distribution, extension and fracture areas, is essential information to evaluate stimulation results. However, there are currently few effective approaches available for quantifying hydraulic fractures in unconventional reservoirs. This work presents an unconventional gas reservoir simulator and its application to quantify hydraulic fractures in shale gas reservoirs using transient pressure data. The numerical model incorporates most known physical processes for gas production from unconventional reservoirs, including two-phase flow of liquid and gas, Klinkenberg effect, non-Darcy flow, and nonlinear adsorption. In addition, the model is able to handle various types and scales of fractures or heterogeneity using continuum, discrete or hybrid modeling approaches under different well production conditions of varying rate or pressure. Our modeling studies indicate that the most sensitive parameter of hydraulic fractures to early transient gas flow through extremely low permeability rock is actually the fracture-matrix contacting area, generated by fracturing stimulation. Based on this observation, it is possible to use transient pressure testing data to estimate the area of fractures generated from fracturing operations. We will conduct a series of modeling studies and present a methodology using typical transient pressure responses, simulated by the numerical model, to estimate fracture areas created or to quantity hydraulic fractures with traditional well testing technology. The type curves of pressure transients from this study can be used to quantify hydraulic fractures in field application.

Impacts of organic ligands on forsterite reactivity in supercritical CO2 fluids.

Subsurface injection of CO2 for enhanced hydrocarbon recovery, hydraulic fracturing of unconventional reservoirs, and geologic carbon sequestration produces a complex geochemical setting in which CO2-dominated fluids containing dissolved water and organic compounds interact with rocks and minerals. The details of these reactions are relatively unknown and benefit from additional experimentally derived data. In this study, we utilized an in situ X-ray diffraction technique to examine the carbonation reactions of forsterite (Mg2SiO4) during exposure to supercritical CO2 (scCO2) that had been equilibrated with aqueous solutions of acetate, oxalate, malonate, or citrate at 50 °C and 90 bar. The organics affected the relative abundances of the crystalline reaction products, nesquehonite (MgCO3 · 3H2O) and magnesite (MgCO3), likely due to enhanced dehydration of the Mg(2+) cations by the organic ligands. These results also indicate that the scCO2 solvated and transported the organic ligands to the forsterite surface. This phenomenon has profound implications for mineral transformations and mass transfer in the upper crust.

Multioriented Fracturing in Unconventional Reservoirs Offers Improved Production by Better Connectivity

Summary In the oil field, the term "unconventional" almost always means difficult to obtain for one or another reason. One reason addressed in this paper relates to formations characterized by the lack of permeable features that connect or can be easily connected to the wellbore using conventional stimulation techniques. The common logic of placing larger and larger fractures does work, but, when using this approach, the cost-to-reward ratio can be far from desirable. It is well known that placing a second fracture sometime later in the life of a well will result in a fracture that extends in a slightly different direction, mostly caused by the drainage of the fluid near the fracture face. In this situation, fracture redirection is probably caused by the pore-pressure decline near the producing fracture face. In some instances, the new fracture produces almost as if it has reached a new formation. This paper discusses placement of such second (or third) hydraulic fractures within the same time domain from the same wellbore section. While this has not yet been performed in the field, it is believed that the first fracture will modify the stress field to a perpendicular direction. Combined with the hypothesis of the hard-to-accept concept that fractures often shy away from the most-productive zones, this approach will cause the second fracture to extend directly into the more-productive zones, thus providing a substantial production boost.

Radius of Investigation and its Generalization to Unconventional Reservoirs

The concept of radius of investigation is fundamental to well test analysis and is routinely used to design well tests and to understand the reservoir volume investigated. The radius of investigation can also be useful in identifying new well locations and planning, designing and optimizing hydraulic fractures in unconventional reservoirs. It has additional implications in estimating reserves and understanding stimulated reservoir volumes. There are many definitions of radius of investigation in the literature and Kuchuk (2009) summarized them recently. Although these definitions vary in detail, they all relate to the propagation of a pressure disturbance or impose thresholds on detectable pressure or rate changes. In this article we will focus on the definition proposed by Lee (1982). Lee defines the radius of investigation as the propagation distance of the “peak” pressure disturbance for an impulse source or sink. For simplified flow geometries and homogeneous reservoir conditions, the radius of investigation can be calculated analytically. However, such analytic solutions are severely limited for heterogeneous and fractured reservoirs, particularly for unconventional reservoirs with multistage hydraulic fractures. Generalization of the Concept How can we generalize the concept of radius of investigation to heterogeneous reservoir conditions including unconventional reservoirs with horizontal wells and multistage hydraulic fractures? For such general situations, it will be more appropriately called “the depth of investigation” rather than the radius of investigation. The simplest, not necessarily the most desirable, approach will be to use a numerical reservoir simulator. For example, we can simulate a constant rate drawdown test and observe the pressure response at every grid block in the simulation model. It is as if, we have distributed sensors throughout the reservoir. We can now compute the time derivative of the pressure at each grid block and note the time when the derivative reaches a maximum. We can then simply contour this “peak” arrival time at every grid block. Note that because the constant rate test corresponds to a step function (from 0 to Q), its derivative is an impulse function. Thus, by contouring the arrival time of the maximum of the pressure derivative, we are actually looking at the arrival time of the maximum of an impulse response as defined by Lee (1982). How well does the approach work? Fig. 1a shows the evolution of the radius of investigation for homogeneous radial flow using Lee’s analytic solution. Fig. 1b shows the radius of investigation obtained from numerical simulation. We have superimposed the analytic solution (black lines) on the results from the numerical simulation. We do see a close correspondence, although the numerical results have difficulties resolving the pressure transients away from the well. In spite of its limitations, the numerical approach is very general and can be applied to arbitrary reservoir and well conditions. The computation time and expenses, however, make the numerical simulation approach unfeasible for routine applications.

Identifying faults and fractures in unconventional reservoirs through microseismic monitoring

Scott A. Wessels, Alejandro De La Peña, Michael Kratz, Sherilyn Williams-Stroud and Terry Jbeili of Microseismic describe how in microseismic monitoring of low permeability reservoirs the use of source mechanism inversion, b values, and energy release rates enables identification and differentiation between fracture stimulation and fault activation, critical issues for effective hydraulic treatment.

Characterization of Hydraulically Induced Fracture Network in a Tight Gas Formation Using Treatment and Microseismic Data

This article, written by Senior Technology Editor Dennis Denney, contains highlights of paper SPE 125237, "Characterization of Hydraulically Induced Fracture Network Using Treatment and Microseismic Data in a Tight Gas Formation: A Geomechanical Approach," by Wenyue Xu, Joël Le Calvez, and Marc Thiercelin, Schlumberger, prepared for the 2009 SPE Tight Gas Completions Conference, San Antonio, Texas, 15-17 June. The paper has not been peer reviewed. Large amounts of gas are produced from unconventional tight-gas-sand reservoirs (e.g., Cotton Valley, Lobo, Taylor Sand, and Wilcox formations) and gas-bearing shale formations (e.g., Barnett, Fayetteville, Marcellus, and Woodford). These plays are driven partly by technology and partly by economics. Modern well-log-evaluation techniques and completion methods are required to yield economical wells. In some cases, microseismic-monitoring campaigns are performed in these low-permeability environments to improve the understanding of the induced-fracture network and to go beyond the simple assumption of a symmetric biwing-fracture system. Introduction Use of traditional models, assuming single- or biwing-type induced fractures, has produced successful hydraulic fracturing in conventional reservoirs. However, these models cannot represent the complex nature of induced fractures in unconventional reservoirs with pre-existing fractures. The otherwise straightforward propagation of a simple wing-like hydraulic fracture tends to interact with nearby pre-existing natural fractures. There are indications of microseismic activity being related to stress effects and to actual fluid movement. In some cases, a volumetric hydraulic-fracturing process is indicated. Recent efforts have been made to map the pattern of induced-fracture networks on the basis of observed microseismic-event distribution. These interpretations were not constrained closely by accounting for the amount of pumped fluid and mechanical interactions between fracture and injected fluid as well as among nearby fractures. Fracture-Network Model To characterize the induced-fracture network better, a semianalytical pseudo-3D geomechanical model was developed on the basis of the conservation of injected-fluid mass and mechanical interactions between fractures and injected fluid as well as among the fractures. The hydraulically stimulated volume is represented by a horizontally expanding ellipse containing a simplified fracture network consisting of two sets of vertical planar fractures perpendicular to one another. This model provides a mathematically equivalent description of the process of hydraulic-fracture propagation and the characteristics of the induced fractures.

The importance of geophysical and petrophysical data integration for the hydraulic fracturing of unconventional reservoirs

Multidisciplinary integration is common in the petroleum industry and is critical for the success of many projects. This paper discusses the need for and importance of multidisciplinary integration of data inputs for the success of hydraulic fracturing treatments in unconventional reservoirs, specifically tight-gas sands and shale systems. Four main areas are discussed, including microseismic, field-wide seismic, petrophysical rock properties, and geological characterization. A discussion of future areas for integration is also provided.

Techbits: Hydraulic Fracturing's Progress Reviewed in Workshop

Techbits Approximately 110 professionals converged on Cartagena, Colombia from 11 to 13 August for SPE's Applied Technology Workshop (ATW) titled "Hydraulic Fracturing in the Americas." The international audience, representing the US, Canada, Mexico, Argentina, Venezuela, Brazil, Colombia, Romania, and Indonesia, shared the latest information on how hydraulic fracturing has been applied to improve hydrocarbon recovery during various stages of field life. Two full days of discussion included 21 high-level fracturing topics divided into six subtopics, including high-permeability and low-permeability fracturing, unconventional reservoirs and horizontal well fracturing, fracture design and diagnostics, and advances in fluids and proppants. The ATW's first session on high-permeability fracturing featured discussions by representatives of Schlumberger, Halliburton, and Ecopetrol-ICP. Highlights of the session included an explanation of how the microannulus between cement and rock favor fracture initiation and propagation, and that a wide propped width is required to provide high fracture conductivity and offset embedment. The leakoff areas above and below a perforated interval help contain fracture height growth and facilitate tip screen out and it is important to consider the cool down temperature profile for proper design of fracturing fluids. Packerless multistage CT fracturing in Argentina using hydra-jet technology is performing well in high-permeability formations and in tight gas sands. Frac design in Colombia includes a procedure for selecting candidates considering reservoir and geomechanical data. Also, organic preflushes have shown excellent results when performed prior to main frac treatment. The second session on low-permeability fracturing considered experiences in the East Kalimantan in Indonesia and the Burgos Basin of Mexico. At East Kalimantan, poroelastic hysteresis is severe, and special considerations need to be taken in fracturing these poroelastic sensitive formations. The main considerations are to follow a rigorous planning schedule and demand high-quality services for fracturing operations. Also, an analysis of the history of fracturing in the area is a must before designing new fracturing jobs. Use of microemulsion technologies has showed good results in the Burgos Basin. Another parameter for success includes getting proper values for rock permeability, closure pressure, and rock mechanical properties from minifrac tests. Flowback tests using chemical tracers showed that the recovery of fracturing fluids after a treatment is in the range of 5–20% of the total injected fluids. In a session discussing the fracturing of unconventional reservoirs, experiences from the Barnett Shale were presented. The speakers recommended accounting for the shale's network of natural fractures, and considering a switch to clean fluids when encountering high pressure due to the large increase of sand concentration near the mouth of the fracture. A return of more than 30% of water is a bad sign for the fracturing job.