Imaging of microseismic data is the process by which we use information about the source locations, timing, and mechanisms of the induced seismic events to make inferences about the structure of a petroleum reservoir or the changes that accompany injections into or production from the reservoir. A few key projects were instrumental in the development of downhole microseismic imaging. Most recent microseismic projects involve imaging hydraulic-fracture stimulations, which has grown into a widespread fracture diagnostic technology. This growth in the application of the technology is attributed to the success of imaging the fracture complexity of the Barnett Shale in the Fort Worth basin, Texas, and the commercial value of the information obtained to improvecompletions and ultimately production in the field. The use of commercial imaging in the Barnett is traced back to earlier investigations to prove the technology with the Cotton Valley imaging project and earlier experiments at the M-Site in the Piceance basin, Colorado. Perhaps the earliest example of microseismic imaging using data from downhole recording was a hydraulic fracture monitored in 1974, also in the Piceance basin. However, early work is also documented where investigators focused on identifying microseismic trace characteristics without attempting to locate the microseismic sources. Applications of microseismic reservoir monitoring can be tracked from current steam-injection imaging, deformation associated with reservoir compaction in the Yibal field in Oman and the Ekofisk and Valhall fields in the North Sea, and production-induced activity in Kentucky, U.S.A.
Abstract. Dynamic micromechanical models are used to analyze crack nucleation and propagation in brittle rock. Models of rock are created by bonding together thousands of individual particles at points of contact. The feasibility of using these bonded particle models to reproduce rock mechanical behavior is explored by comparing model behavior to results from actual laboratory tests on different rock types. The behavior of two granite models are examined in detail to study cracking and failure patterns that occur during compressional loading. Because discontinuum models are being used, the rock models are free to crack and break apart under stress, such that the micromechanics of cracking can be examined. Stress waves are allowed to propagate outward from each crack, and it is shown that these dynamic waves significantly affect the rock behavior. As the peak stress in the modeled rock is approached and many of the bonds are close to breaking, a passing wave from a nearby crack is sufficient to break more bonds. This causes clusters of cracks to be created, and then eventual macroscopic shear failure occurs as these clusters connect to bisect the sample. The failure patterns observed in the granite models are similar to those observed in actual laboratory tests. . These studies show that in sandstones, shear localization usually does not develop until after the peak stress has been reached. Most of the cracking occurring before the peak stress appears to be intergranular (between grains). This is a departure from low-porosity crystalline rocks (granite) in which many of the cracks are intragranular [Tapponnier and Brace, 1976]. In sandstones it appears that most cracking occurs along grain boundaries, either by widening of preexisting microcracks or by shear rupturing of the cement at the grain contacts caused by rotation and slip of the grains. The high level of acoustic emissions (AE) recorded during dilation gives evidence that this second process is occurring. 16,683
In this paper we present results from a series of laboratory hydraulic fracture experiments designed to investigate various components of the energy budget. The experiments involved a cylindrical sample of Westerly granite being deformed under various triaxial stress states and fractured with distilled water, which was injected at a range of constant rates. Acoustic emission sensors were absolutely calibrated, and the radiated seismic energy was estimated. The seismic energy was found to range from 7.02E−8% to 1.24E−4% of the injection energy which is consistent with a range of values for induced seismicity from field‐scale hydraulic fracture operations. The deformation energy (crack opening) of the sample during hydraulic fracture propagation was measured using displacement sensors and ranged from 18% to 94% of the injection energy. Our results support the conclusion that aseismic deformation is a significant term in the hydraulic fracture energy budget.
Microseismic monitoring has been used to image hydraulic fracture growth in the Barnett Shale. The Barnett is a naturally fractured shale reservoir, which causes significant complexity in fracture growth during well stimulation operations. Several Barnett treatments have been successfully imaged between March 2000 and December 2001. In this paper, examples will be given to illustrate the complexity and variability which is developed during the treatment as the slurry interacts with the pre-existing fracture sets. The microseismic images explain why the stimulations occasionally grow at an angle to the assumed fracture orientation and into neighboring wells. Differences in production rates from various wells could also be related to the fracture geometry. The implications of the images to reservoir management highlight the benefit of imaging individual fracture networks to avoid overlapping and for targeting potential new well locations. Introduction Fracture diagnostics is critical in understanding the details of actual subsurface fracture growth, especially in cases of fracture complexity. Several diagnostic techniques exist, although microseismic imaging perhaps offers the best resolution to image fracture complexity. Even with relatively simple fracture geometries (i.e. a Perkins-Kern type fracture geometry), fractures can grow asymmetrically, have variable confinement across geologic interfaces, and change orientation. However, fracture growth in a naturally fractured reservoir can exhibit additional complexities associated with interaction between the hydraulic fracture and the pre-existing fracture network. In this paper, we describe the results of microseismic imaging of hydraulic fractures in Devon Energy's (formerly Mitchell Energy) Barnett Shale Gas Field, Texas1–4. The images are the first successful microseismic images in the Barnett, recorded between March 2000 and December 2001. The field is in the Fort Worth Basin, comprising the Mississippian shale lying between the Viola Limestone and the Marble Falls Limestone. The shale varies between 300' to 1000' thick, and is extremely low permeability (approximately 0.0001 millidarcies). Large scale hydraulic fracturing is required to stimulate production in the field to economic levels1. The objective of the microseismic imaging was to define the fracture growth characteristics during these well stimulations. The large scale hydraulic fractures, combined with infill drilling on spacing as tight as 27 acres and apparenent fracture complexity related to interaction with pre-existing fractures, resulted in a need to better understand the fracture geometry5. To image the actual fracture behavior in the field, a series of stimulations have been imaged using passive microseismic imaging to determine the fracture geometry and growth characteristics. Here, we present selected examples from images collected during numerous stimulations over a period of two years, which demonstrate substantial fracture complexity resulting from interaction with the natural fractures in the field. The paper reports the fracture geometry and complexity, comparisons with the final well production, and implications for field management.
Microseismic monitoring of hydraulic fractures is an important tool for imaging fracture networks and optimizing the reservoir engineering of the stimulation. The range of magnitudes of the recorded microseisms depends at the lower limit on the array sensitivity; while the upper limit varies significantly from site to site. In this paper the variation in the microseismic magnitude range is examined and compared with the injection and site characteristics. Although there are numerous potential factors effecting the seismic deformation, the energy of the pumping and state of stress appear to be the two dominant factors. However, interaction with pre-existing faults also results in increased deformation. Ultimately, this can potentially be used to design the stimulation to maximize the deformation. Characterization of the seismogenic potential is also important for seismic hazard assessment, as well as the design of passive monitoring. Introduction Over the last few years, microseismic imaging of hydraulic fracture stimulations 1 has become a widespread diagnostic technology. Microseismicity is used to image fracture geometry dynamics and optimize stimulations in a wide variety of settings. The resulting images are useful in both simple and complex fracture networks and able to detect fracture complexity resulting from injections in naturally fractured reservoirs. Particularly in North America, microseismic imaging has become a standard in development of both conventional and unconventional resource plays. Generally, the temporal locations of microseisms detected in an offset observation well are used to monitor the growth of the hydraulic fracture geometry. In most cases the hydraulic fracture is being created by tensile failure of the rock resulting from injection of fluids at pressures exceeding the minimum principal stress level, although the deformation mechanism associated with the recorded microseisms appears to be shear dominated deformations. Microseisms typically contain significant shear wave energy suggesting substantial shear deformation in the source of the microseismic energy, although fracture opening could occur simultaneous with the shear deformation and play a role in the permeability enhancement. One model to explain the shearing is stress changes or pore pressure increases associated with the primary hydraulic fracture 2, leading to induced shear failure. However, dog legs, offsets or other complexities along the hydraulic fracture could also result in localized shear deformations along a conventional tensile fracture. Intersections of a hydraulic fracture with oblique angle pre-existing fractures could also lead to localized shear deformation. Microseism signal analysis can be used to investigate aspects of the source characteristics of the shear deformation, although this may or may not provide insight into the stimulation objective of creating a permeable fracture possibly containing a fluid conductive proppant pack. An important microseism source attribute is the source strength or magnitude 3. Source strength is best quantified by seismic moment (product of shear modulus, shear displacement and area) which can be expressed with a moment magnitude scale, analogous to the well known Richter Magnitude scale. Investigating source strength has proven valuable in determining the effective detection range, by simply plotting magnitude versus distance between the microseisms and seismometers. However, the spatial extent of the seismic deformation has been postulated to image the extent and density of a stimulated fracture network in the Barnett Shale, and appears to provide a useful attribute that correlates with gas production in a case study examining several wells 4.
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