Shawn Maxwell

Petroleum reservoir characterization using downhole microseismic monitoring

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 ...

Micromechanical modeling of cracking and failure in brittle rocks

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.

The role of passive microseismic monitoring in the instrumented oil field

With the current industry trend toward instrumented oil fields and smart well completions, the permanent deployment of geophones or other acoustic sensors to complement standard engineering gauges is being promoted as a way to map reservoir dynamics. The biggest push is from the time-lapse seismic practitioners, although the deployment of permanent seismic instrumentation is also potentially an ideal route to monitor passive seismicity.

Microseismic: Growth born from success

Over the last several years, microseismic (MS) monitoring has quickly grown as a technology to map various reservoir processes. Imaging hydraulic fracture stimulations is the most common application especially within North America. As indicated in the introduction to this special section, initial interest in MS was primarily in the engineering community. As the method was pushed forward by the engineers, geophysicists within operating companies began to get pulled in to support the engineering projects. As application of the method gathered steam, interest expanded in the geophysical community and into academia as seen by the growth of research consortia looking at the technique. While MS is a seismic technique, it is sufficiently novel that most geophysicists are largely uninformed about technology challenges. Nevertheless, over the last few years the geophysical community has been both educating itself and taking stewardship of the technology. MS remains a unique geophysical technology although the tech...

Hydraulic Fracture Monitoring to Reservoir Simulation: Maximizing Value

Hydraulic fracture monitoring with microseismic mapping is now routinely used to measure hydraulic fracture geometry, location, and complexity, providing an abundance of information that can be essential to optimizing stimulation treatments and well completions. Although microseismic mapping has added significant value in many different environments, we have yet to fully utilize microseismic data. Significant details can be extracted from microseismic measurements that, when integrated with other information, can improve the characterization of both the reservoir and the hydraulic fracture. In addition, microseismic data has yet to be quantitatively and routinely utilized in reservoir simulation, which is the key to optimization.

Microseismic hydraulic fracture imaging: The path toward optimizing shale gas production

Economic shale gas production involves hydraulic fracture stimulation in order to create permeable flow paths within these low-permeability reservoirs. Microseismic monitoring has shown that often these “fracs” consist of complex fracture networks, with large surface contact areas with the reservoir. Optimized production is therefore dependent on the ability of the stimulation to activate an extensive fracture network. Much of the current attention around hydraulic fractures focuses on microseismic imaging of the activated network; however, the path toward optimized shale gas production also requires methods to both predict and model the fracture networks. Along the path, engineers will be able to close the loop for an optimally designed stimulation: being able to predict, monitor, and assess the stimulated fracture network. As an industry, we are just starting down this path, and this paper describes a few case studies that highlight recent advancements. Before we can ultimately predict the fracture netw...

What Does Microseismicity Tells Us About Hydraulic Fractures

Summary Microseismic imaging has proven valuable in imaging hydraulic fracture geometry. However, the relationship between the microseismic deformation and the geomechanical response of the rock to the hydraulic fracturing process needs to be properly understood in order to exploit additional microseismic attributes to better characterize the hydraulic fracture. Here, observations are given that shows that the microseismic deformation represents a high-frequency, predominantly shearing and small proportion of the deformation in contrast with the slow, predominantly aseismic, tensile hydraulic fracture opening. A common engineering interpretation of the hydraulic fracture effectiveness is the total stimulated volume of the reservoir, typically based on the microseismically active volume. The volume of the microseismic cloud is shown to represent an overestimation of microseismic deforming volume depending on the microseismic location uncertainties, which in turn can include stress induced deformation and so is an upper limit on the hydraulically created fracture volume. The microseismic does describe the relative proportion of the geomechanically deforming rock and when interpreted in light of a complex fracture mechanics model can be used to estimate the extent and effectiveness of the open, flowing hydraulic fracture.

A comparison of passive seismic monitoring of fracture stimulation from water and CO2 injection

Hydraulic fracturing is used to create pathways for fluid migrationandtostimulateproduction.Usually,wateristheinjected fluid, although alternative fluids such as carbon dioxide CO2 have been used recently. The amount of fracturing that CO2 can induce is also of interest for the security of carbon capture and storage. Hydraulic fracturing is usually monitored using passive seismic arrays, detecting microseismic events generated by the fracturing. It is of interest to compare the amount of seismicity that CO2 injection can generate in comparison with water. With this in mind, we have analyzed a passive seismic data set monitoring the injection of water and supercritical CO2 under very similar conditions, allowing us to make a direct comparison between the fluids.We examined event locations and event magnitudes, and we used shear-wave splitting to image the fractures that are generated. For both fluids,the event locations map the formation of fractures moving away from the injection well with normalsparalleltotheminimumprincipalstress.Theeventsduring water injection are limited to the injection depth, while during CO2 injection, activity migrates above the injection depth. Eventmagnitudesaresimilarinbothcases,andlargereventmagnitudes appear to correlate with higher injection pressures. Shear-wave splitting suggests that water injection generates more fractures, though the data quality is not good enough to make a robust conclusion about this.The comparability between water and CO2 injection means that lessons can be learned from theabundantexperienceofconventionalwaterinjection.

Understanding Hydraulic Fracture Variability Through Integrating Microseismicity and Seismic Reservoir Characterization

Microseismic measurements were integrated with seismic reservoir characterization and injection data to investigate variability in the hydraulic fracture response between three horizontal wells in the Montney shale in NE British Columbia, Canada. When wells were close enough, hydraulic fractures were found to interact with pre-existing faults, which acted as a barrier to fracture growth, and resulted in relatively large-magnitude microseismicity.

A comparison of passive seismic monitoring of fracture stimulation due to water versus CO2 injection

The principal observation from passive seismic monitoring at the Weyburn CCS/EOR project has been a very low rate of microseismicity. This has lead to the suggestion that, as CO2 has a higher compressibility, when injected it will have a lower seismic eff