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.

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.

Proposal This paper discusses the integration of microseismic fracture mapping with fracture engineering, well production results and offset well interference data in the Overton Field, East Texas. Target formation is the Taylor Cotton Valley at depths of about 11,500 ft. The fracturing program in this field included different types of waterfrac and linear gel hybrid frac treatments, which were compared to evaluate the optimal type of fracture design in this area. Detailed production analyses were performed to evaluate well performance in conjunction with fracture geometry measurements provided by microseismic fracture mapping results, calibrated fracture modeling and direct production interference data, which provided interesting insights into effective fracture lengths, reservoir quality, and drainage areas. Microseismic fracture mapping1,2,4,6,7,14–17 indicated that created fractures are very long. There is compelling evidence that effective hydraulic fracture lengths are also very long, as immediate well interference can be detected in wells that are located along the fracture orientation with very large inter-well distances. This means that there is a conductive hydraulic fracture path in place over large distances, with fractures overlapping and linking up wells. One well in this study area was temporarily killed by a fracture treatment in an offset well but production was restored within one day. There was no evidence for a wide fracture network (as has been reported in the Barnett shale), but there may be a small-scale fracture network within a narrow area around the hydraulic fracture. Production modeling indicates that the permeability feeding the long hydraulic fractures (perpendicular to frac) is on average very low as indicated by production modeling. The low permeability and long fractures will create slim "cigar-like" drainage areas that should be taken into consideration for well placement and spacing strategies. The results of this work illustrate the application of microseismic mapping to calibrate fracture models3,8,9,10,13and, with the subsequent integration of production and interference data, to improve well placement and field development strategies. The paper also provides recommendations for optimizing future fracture treatment designs and explores different treament types (waterfracs, and linear gel hybrid fracs) and the effect of increasing job sizes. Introduction The target zones are three to four low permeability gas sands in the Taylor section of the Cotton Valley at depths of about 11,200 to 11,500 ft (Figure 1). Porosities are in the range of 9% to 11% with water saturations of 17% to 30%. Pore pressures are slightly over-pressured at about 0.60 psi/ft. Wells are generally perforated in three to four clusters (one cluster in each sand layer) with 1 shot per foot perforation density. Fracture completions are generally performed in one stage. The type of fracture treatment has evolved over time in several phases, including conventional gel fracs, waterfracs and hybrid fracs. The original crosslinked gel treatments were performed in the 1980's. Waterfrac treatments were implemented in 2001 after the current operator purchased the field. Microseismic fracture mapping was performed on one well and provided measurements of fracture geometry and azimuth. The combination of fracture geometry measurements, fracture modeling, production modeling, and production interference data provided the framework for this study.

Surface deformation measurements have been used for years in oilfields to monitor production, waterflooding, waste injection, steam flooding, and Cyclic Steam Stimulation (CSS). They have been proven to be a very effective way to monitor the field operations and save money for operators wishing to avoid unwanted surface breeches, casing failures and excessive subsidence due to production. This paper demonstrates that more information can be extracted from surface deformation measurements by inverting the surface deformation for the volumetric deformation at the reservoir level, so the aerial distribution of volumetric deformation can be identified. First, a poroelastic model is presented to calculate the deformation due to the volumetric change in the reservoir. Then, a linear geophysical model is formulated to invert for the reservoir volumetric deformation from the measured surface deformation (or tilt). Constraints are added into the procedure as necessary to better resolve the inversion problem. After each inversion, the theoretical surface deformation (displacement, tilt, reservoir compaction and volumetric strain) can be calculated from the inverted volumetric deformation distribution which best fits the measured deformation data (or tilt) at the surface. The technique of mapping fluid flow using surface deformation was applied to real data from a cyclic steam injection project. Introduction Through the decades, many oil companies and individual researchers have studied reservoir compaction and its associated surface subsidence. Two techniques are used: forward modeling for prediction and direct measurements (or monitoring). The forward modeling includes numerical analysis using Finite Element Method and analytical or semi-analytical analysis. The most common monitoring techniques used in oil and gas fields are:Optical instrument leveling surveys or Global Positioning System (GPS) surveys[1]. These are conducted continuously or periodically to determine changes in position of monuments across the field.Interferometric Synthetic Aperture Radar (InSAR) [1]. This enables mapping of surface displacement along the satellite line of sight over large areas.Tiltmeter-based surface deformation monitoring[2,3]. High precision tiltmeters are placed near the earth's surface to measure the displacement gradient (tilt) induced by field operations such as fluid injection and production. Each technique has advantages and disadvantages, and in some cases two or even all three can be used in combination to get the necessary combination of precision, spatial coverage and temporal resolution. In the case history shown here, only tiltmeter data is used and the inversion process calculates and compares measured and theoretical tilt, but only minor changes are needed to perform the same calculations with displacement.