The Barnett Shale of North Texas is an ultra low permeability reservoir that must be effectively fracture stimulated in order to obtain commercial production. As a result, techniques to optimize hydraulic fracturing effectiveness have evolved over the past decade.
Summary This paper presents an analysis of the stress and pressure changes caused by hydraulic fractures and evaluates the likelihood and causes of microseismic activity in the vicinity of the fracture. Along with the formation stresses, pressure, and properties, the analysis predicts where microseisms should occur in relation to the fracture and makes possible accurate interpretation of the significance of the microseismic events. The most important factor controlling the seismically active zone is the coupling of the fracturing pressure into the formation. Thus, liquid-saturated reservoirs experience much more widespread activity than do gas reservoirs. The analysis also shows that the fracture tip induces large shear stresses that result in a local zone of instability. Such a zone is the primary reason that microseisms accurately map out the length and height of the fracture, because considerable microseismic activity occurs around the tip as it propagates. Introduction Hydraulic-fracturing results have improved immensely since the inception of this process as a direct result of advanced models, detailed pressure analyses, and application of standard diagnostics. However, the full optimization of hydraulic fracture-stimulations will not be possible until accurate methods are available to directly image the fracture size, shape, and characteristics. At this time, the only two methods available for in-situ imaging are, first, the detection of fracture-induced microseismic events using downhole receiver arrays1–14 and, second, the monitoring of fracture-induced deformation using downhole tiltmeter arrays.9,15-21 Both of these techniques have their individual strengths, weaknesses, and interpretation difficulties, but they have been shown to be valuable tools for fracture imaging under the appropriate conditions. Microseismic monitoring, which is the technique considered here, can image the full fracture geometry and also has the capability of extracting very detailed information on fracture complexity.9 In addition, microseismic events contain embedded information about the source of the energy that may be useful for understanding the hydraulic-fracture process.22,23 Nevertheless, this interpretation cannot be done accurately without a full understanding of the stress regime (both in situ and fracture induced) that is generating the microseisms. The understanding of this "structural con text" for interpreting hydraulic fractures is the subject of this paper. Before analyzing the structural context, a short review of a typical microseismic analysis is provided. Microseismic events analyzed in many different settings have been shown to be primarily shear movements of a limited-area rock surface (e.g., Pearson22). The actual tensile cracking of the fracture is not usually detected. In the simplest 2D case, a pure shear movement emits both compressional waves (P waves), with maximum energy at 45° angles to the slip direction, and shear waves (S waves), with maximum amplitude parallel and perpendicular to the slippage direction. However, pure shear is unlikely, and some compressional or dilatational motion perpendicular to the slippage plane is likely (e.g., the slippage riding up over asperities or shearing asperities). This movement will add other complications to the radiation pattern. Nevertheless, detection of the P-wave and S-wave arrivals provides all of the information to accurately locate the source point of the event. Given an accurate velocity structure for both the P waves and S waves, several detected arrival times for each phase can be used in a regression or minimization scheme to provide a best-fit location with error estimates.14 For an array in a single well, this location can be found only in a 2D framework (elevation and radial distance). The direction horizontally to the source must be determined by examining the particle motion of the P waves, which is always directed toward (or away from) the source. Using this procedure, 3D locations can be found using a single vertical array. In the microseismic technique, the locations of these shear events are used to generate an image of a growing fracture. However, these shear slippages are often found tens or hundreds of feet from the fracture, and an exact understanding of the cause of these events is needed to correctly interpret the characteristics of the fracture that is being imaged. In addition, other source information extracted from these microseisms needs to be considered within the structural context. Structural Context The structural context is the setting under which microseismic events are generated and includes formation conditions (stress, pore pressure, mechanical properties, orientation and strength of weakness planes) and fracture-induced conditions (stress, leakoff, temperature). Obviously, the fracture-induced conditions are dependent on formation properties (mechanical and reservoir) as well as treatment conditions (rate, viscosity, leakoff control). In-Situ Stress Conditions. The in-situ stress conditions include the values of the three principal stresses (smin, smax, and sov), their orientations, and the reservoir pressure. These conditions provide some shear stress for favorably oriented weakness planes (e.g., natural fractures), an initial normal stress on the weakness planes (for friction), and a closure stress on the fracture. A check should always be made that the reservoir is not unstable under the initial conditions that are assumed. Fracture-Induced Stresses. The fracture-induced stresses are the stresses generated in the rock mass attributable to the opening of the hydraulic fracture. These stresses depend upon the size of the fracture, the pressure within the fracture, and the mechanical properties of the rock. The calculation of the stresses around a hydraulic fracture in a typical layered medium is a difficult problem requiring finite-element calculations and considerable input data that are seldom available. In this analysis, the problem is simplified by assuming a homogeneous material that is linearly elastic. However, the 3D aspect of the problem is retained by using Green and Sneddon's solution24 for a flat, elliptic crack. The geometry for this solution is shown in Fig. 1. The coordinates x and y are within the crack plane, a complex variable z is defined as x+iy, and the axis normal to the crack surface is defined by the Z coordinate.
A large hydraulic fracture diagnostic project was undertaken in the summer of 2001, which integrated fracture diagnostic technologies including tiltmeter (surface and downhole) and microseismic mapping. The extensive data gathered resulted in a much clearer understanding of the highly complex fracture behavior in the Barnett Shale of North Texas. The detailed fracture mapping results allowed construction of a calibrated 3-D fracture simulator that better reflects the observed mechanics of fracturing in this fractured-shale reservoir. More than just simple calibration was required. Indeed, a whole new understanding of fracture growth was developed. The Barnett Shale has seen a rebirth of drilling and refracturing activity in recent years due to the success of waterfrac or "light sand" fracturing treatments. This extremely low permeability reservoir benefits from fracture treatments that establish long and wide fracture fairways, which result in connecting very large surface areas of the formation with an extremely complex fracture network. Understanding the created fracture geometry is key to the effectiveness of any stimulation program or infill-drilling program, particularly in this area with its non-classical fracture networks. Integrated fracture diagnostics have led to the identification of new fracturing techniques as well as additional refrac and infill drilling candidates. A new method for evaluating large microseismic data sets was developed. Combining the microseismic analysis with surface and downhole tilt fracture mapping allowed characterization of the created fracture networks. Correlations between production response and various fracture parameters will be presented along with a discussion of methods for calibrating a fracture model to the observed fracture behavior. Barnett Basics The Mississippian-age Barnett Shale is a marine shelf deposit that unconformably lies on the Ordovician-age Viola Limestone / Ellenburger Group and is conformably overlain by the Pennsylvanian-age Marble Falls Limestone. The Barnett Shale within the Fort Worth Basin ranges from 200 to 800 feet in thickness and is approximately 500 feet thick in the core area of the field. The productive formation is typically described as a black, organic-rich shale composed of fine grained, non-siliciclastic rocks with extremely low permeability, ranging from.00007 to.005 millidarcies. The formation is abnormally pressured and hydraulic fracture treatments are necessary for commercial production due to the low permeability.
This paper presents an analysis of the stress and pressure changes caused by hydraulic fractures and evaluates the likelihood and causes of microseismic activity in the vicinity of the fracture. Coupled with the formation stresses, pressure, and properties, the analysis predicts where microseisms should occur in relation to the fracture and makes possible accurate interpretation of the significance of the microseismic events. The most important factor controlling the seismically active zone is the coupling of the fracturing pressure into the formation. Thus, liquid -saturated reservoirs experience much more widespread activity than gas reservoirs. The analysis also shows that the fracture tip induces large shear stresses that result in a local zone of instability. Such a zone is the primary reason that microseisms accurately map out the length and height of the fracture since considerable microseismic activity occurs around the tip as it propagates Introduction Although hydraulic fracturing results have improved immensely since the inception of this process due to improved models, pressure analyses, and standard diagnostics, the full optimization of hydraulic fracture stimulations will not be possible until accurate methods are available to directly image the fracture size, shape, and characteristics. At this time, the only methods available for in situ imaging are through the detection of fracture-induced microseismic events using downhole receiver arrays1–15 and by the monitoring of fracture-induced deformation using downhole tiltmeter arrays9,16–22. Both of these techniques have their individual strengths, weaknesses, and interpretation difficulties, but they have been shown to be valuable tools for fracture imaging under the appropriate conditions. Microseismic monitoring, which is the technique considered here, can image the full fracture geometry and also has the capability of extracting very detailed information on fracture complexity.9 In addition, microseismic events contain embedded information about the source of the energy that may be useful for understanding the hydraulic-fracture process.23,24 Nevertheless, none of this interpretation can be done accurately without a full understanding of the stress regime (both in situ and fracture induced) that is generating the microseisms. The understanding of this "structural context" for interpreting hydraulic fractures is the subject of this paper. Before analyzing the structural context, a short review of a typical microseismic analysis is provided. Microseismic events analyzed in many different setting have been shown to be primarily shear movements of a limited-area rock surface (e.g., Pearson23). The actual tensile cracking of the fracture is not usually detected. In the simplest 2-dimensional case, a pure shear movement emits both compressional waves (p waves), with maximum energy at 45° angles to the slip direction, and shear waves (s waves) with maximum amplitude parallel and perpendicular to the slippage direction. However, pure shear is unlikely and some compressional or dilatational motion perpendicular to the slippage plane is likely (e.g, the slippage riding up over asperities or shearing asperities). This movement will add other complications to the radiation pattern. Nevertheless, detection of the p-wave and s-wave arrivals provide all of the information to accurately locate the source point of the event. Given an accurate velocity structure for both the p waves and s waves, several widely spaced arrivals for each phase can be used in a regression or minimization scheme to provide a best-fit location with error estimates.15 For an array in a single well, this location can only be found in a 2–dimensional framework (elevation and radial distance). The direction horizontally to the source must be determined by examining the particle motion of the p waves, which is always directed towards (or away from) the source. Using this procedure, 3–dimensional locations can be found using a single vertical array.
This paper summarizes the results obtained from a comprehensive, joint-industry field experiment designed to improve the understanding of the mechanics and modeling of the processes involved in the downhole injection of drill cuttings. The project was executed in three phases: drilling of an injection well and two observation wells (Phase 1); conducting more than 20 intermittent cuttings-slurry injections into each of two disposal formations while imaging the created fractures with surface and downhole tiltmeters and downhole accelerometers (Phase 2); and verifying the imaged fracture geometry with comprehensive deviated-well (4) coring and logging programs through the hydraulically fractured intervals (Phase 3).Drill cuttings disposal by downhole injection is an economic and environmentally friendly solution for oil and gas operations under zero-discharge requirements. Disposal injections have been applied in several areas around the world and at significant depths where they will not interfere with surface and subsurface potable water sources. The critical issue associated with this technology is the assurance that the cuttings are permanently and safely isolated in a cost-effective manner.The paper presents results that show that intermittent injections (allowing the fracture to close between injections) create multiple fractures within a disposal domain of limited extent. The paper also includes the conclusions of the project and an operational approach to promote the creation of a cuttings disposal domain. The approach introduces fundamental changes in the design of disposal injections, which until recently was based upon the design assumption that a large, single storage fracture was created by cuttings injections.
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