The petroleum engineering literature clearly shows that large proppant volumes and concentrations are required to effectively stimulate low-permeability gas sands. To pump large proppant concentrations, one must use a viscous fluid. However, many operators believe that low-viscosity, low-proppant concentration fracture stimulation treatments known as ??waterfracs?? produce comparable stimulation results in low-permeability gas sands and are preferred because they are less expensive than gelled fracture treatments. This study evaluates fracture stimulation technology in tight gas sands by using case histories found in the petroleum engineering literature and by using a comparison of the performance of wells stimulated with different treatment sizes in the Cotton Valley sands of the East Texas basin. This study shows that large proppant volumes and viscous fluids are necessary to optimally stimulate tight gas sand reservoirs. When large proppant volumes and viscous fluids are not successful in stimulating tight sands, it is typically because the fracture fluids have not been optimal for the reservoir conditions. This study shows that waterfracs do produce comparable results to conventional large treatments in the Cotton Valley sands of the East Texas basin, but we believe it is because the conventional treatments have not been optimized. This is most likely because the fluids used in conventional treatments are not appropriate or have not been used appropriately for Cotton Valley conditions.

The New Albany Shale is an Upper Devonian organic-rich gas shale located in the Illinois Basin. A factor influencing gas production from the shale is the natural fracture system. I test the hypothesis that a combination of outcrop and core observations, rock property tests, and geomechanical modeling can yield an accurate representation of essential natural fracture attributes that cannot be obtained from any of the methods alone. Field study shows that New Albany Shale outcrops contain barren (free of cement) joints, commonly oriented in orthogonal sets. The dominant set strikes NE-SW, with a secondary set oriented NNW-SSE. I conclude that the joints were likely created by near-surface processes, and thus are unreliable for use as analogs for fractures in the reservoir. However, the height, spacing, and abundance of the joints may still be useful as guides to the fracture stratigraphy of the New Albany Shale at depth. The Clegg Creek and Blocher members contain the highest fracture abundance. Fractures observed in four New Albany Shale cores are narrow, steeply-dipping, commonly completely sealed with calcite and are oriented ENE-WSW. The Clegg Creek and Blocher members contain the highest fracture abundance, which is consistent with outcrop observations. Fractures commonly split apart along the wall rock-cement interface, indicating they may be weak planes in the rock mass, making them susceptible to reactivation during hydraulic fracturing. Geomechanical testing of six core samples was performed to provide values of Young’s modulus, subcritical index, and fracture toughness as input parameters for a fracture growth simulator. Of these inputs, subcritical index is shown to be the most influential on the spatial organization of fractures. The models predict the Camp Run and Blocher members to have the most clustered fractures, the Selmier to have more evenly-spaced fractures, and the Morgan Trail and Clegg Creek to have a mixture of even spacing and clustering. The multi-faceted approach of field study, core work, and geomechanical modeling I used to address the problem of fracture characterization in the New Albany Shale was effective. Field study in the New Albany presents an opportunity to gather a large amount of data on the characteristics and spatial organization of fractures quickly and at relatively low cost, but with questionable reliability. Core study allows accurate observation of fracture attributes, but has limited coverage. Geomechanical modeling is a good tool for analysis of fracture patterns over a larger area than core, but results are difficult to corroborate and require input from outcrop and core studies. / text

published_or_final_version / Applied Geosciences / Master / Master of Science

The primary objective of this study is to improve understanding of the mechanics of hydraulic fracturing in naturally-fractured reservoirs. The study focuses on enhancing the interpretation of hydraulic fracture-induced microseismic data using an S-wave Gaussian-beam method and numerical modeling techniques for interpretation. The S-wave Gaussian-beam method was comprehensively calibrated by synthetic and real data sets with different recording networks, and this showed the potential to retrieve additional microseismic data from hydraulic fracturing with linear receiver arrays. This approach could enhance current practice because a large number of induced events in these environments have very strong S-waves with P-wave amplitudes similar, or less than, background noise levels. The numerical study using the distinct element methods PFC2D and PFC3D was used to validate the understanding of the hydraulic fracturing mechanisms induced in laboratory and field fluid treatments in naturally-fractured reservoirs. This was achieved through direct comparison with the results of the geometry of hydraulic fractures and seismic source information (locations, magnitudes, and mechanisms) from both laboratory experiments and field observations. A suite of numerical models with fully-dynamic and hydro-mechanical coupling has been used to examine in detail the interaction between natural and induced fractures with the variations of the differential stresses and the orientations of the pre-fractures, and the relationship between the fluid front, the fracture tip, and the induced seismicity. The numerical results qualitatively agreed with the laboratory and field observations of the geometry of hydraulic fractures, confirmed the possible mechanics of new fracture development and their interactions with natural fractures, and illustrated the possible relationship between the fluid front and the fracture tip. The validated model could therefore help track the potential extent of induced fracturing in naturally-fractured reservoirs and the extent to which it can be detected by a microseismic monitoring array in order to assess the effectiveness of a hydraulic fracturing project.

Volatile organic compound (VOC) contamination of low permeability geologic deposits due to Dense Non-Aqueous Phase Liquid (DNAPL) penetration through fractures is exceptionally difficult to remediate using in-situ methods as the low permeability of the sediments limits the delivery of reagents proximal to contaminant mass. This thesis examines in detail the extent of organic contaminant treatment away from hydraulically-induced fractures injected with particulate Zero Valent Iron as (1) ZVI and glycol (G-ZVI) and (2) an emulsified ZVI (EZVI) mixture within a contaminated glaciolacustrine clayey deposit. Continuous vertical cores were collected through the treatment zone at 2 and 2.5 years after substrate injections and soil sub-sample spacing was scaled to show the extent of the treatment zone adjacent to the ZVI in the fractures, expecting the treatment would be controlled by diffusion limited transport to the reaction zone. Analytical results show evidence of treatment in both the EZVI and the G-ZVI containing fractures with the presence of degradation by-products and reduced VOC concentrations in the fracture and surrounding clay matrix. / Natural Sciences and Engineering Research Council of Canada, University Consortium for Field-Focused Groundwater Contamination Research

Better understanding and control of crack growth direction during hydraulic fracturing are essential for enhancing productivity of geothermal and petroleum reservoirs. Structural analysis of fracture propagation and impact on fluid flow is a challenging issue because of the complexity of rock properties and physical aspects of rock failure and fracture growth. Realistic interpretation of the complex interactions between rock deformation, fluid flow, heat transfer, and fracture propagation induced by fluid injection is important for fracture network design. In this work, numerical models are developed to simulate rock failure and hydraulic fracture propagation. The influences of rock deformation, fluid flow, and heat transfer on fracturing processes are studied using a coupled thermo-hydro-mechanical (THM) analysis. The models are used to simulate microscopic and macroscopic fracture behaviors of laboratory-scale uniaxial and triaxial experiments on rock using an elastic/brittle damage model considering a stochastic heterogeneity distribution. The constitutive modeling by the energy release rate-based damage evolution allows characterizing brittle rock failure and strength degradation. This approach is then used to simulate the sequential process of heterogeneous rock failures from the initiation of microcracks to the growth of macrocracks. The hydraulic fracturing path, especially for fractures emanating from inclined wellbores and closed natural fractures, often involves mixed mode fracture propagation. Especially, when the fracture is inclined in a 3D stress field, the propagation cannot be modeled using 2D fracture models. Hence, 2D/3D mixed-modes fracture growth from an initially embedded circular crack is studied using the damage mechanics approach implemented in a finite element method. As a practical problem, hydraulic fracturing stimulation often involves fluid pressure change caused by injected fracturing fluid, fluid leakoff, and fracture propagation with brittle rock behavior and stress heterogeneities. In this dissertation, hydraulic fracture propagation is simulated using a coupled fluid flow/diffusion and rock deformation analysis. Later THM analysis is also carried out. The hydraulic forces in extended fractures are solved using a lubrication equation. Using a new moving-boundary element partition methodology (EPM), fracture propagation through heterogeneous media is predicted simply and efficiently. The method allows coupling fluid flow and rock deformation, and fracture propagation using the lubrication equation to solve for the fluid pressure through newly propagating crack paths. Using the proposed model, the 2D/3D hydraulic fracturing simulations are performed to investigate the role of material and rock heterogeneity. Furthermore, in geothermal and petroleum reservoir design, engineers can take advantage of thermal fracturing that occurs when heat transfers between injected flow and the rock matrix to create reservoir permeability. These thermal stresses are calculated using coupled THM analysis and their influence on crack propagation during reservoir stimulation are investigated using damage mechanics and thermal loading algorithms for newly fractured surfaces.

The primary objective of this study is to improve understanding of the mechanics of hydraulic fracturing in naturally-fractured reservoirs. The study focuses on enhancing the interpretation of hydraulic fracture-induced microseismic data using an S-wave Gaussian-beam method and numerical modeling techniques for interpretation. The S-wave Gaussian-beam method was comprehensively calibrated by synthetic and real data sets with different recording networks, and this showed the potential to retrieve additional microseismic data from hydraulic fracturing with linear receiver arrays. This approach could enhance current practice because a large number of induced events in these environments have very strong S-waves with P-wave amplitudes similar, or less than, background noise levels. The numerical study using the distinct element methods PFC2D and PFC3D was used to validate the understanding of the hydraulic fracturing mechanisms induced in laboratory and field fluid treatments in naturally-fractured reservoirs. This was achieved through direct comparison with the results of the geometry of hydraulic fractures and seismic source information (locations, magnitudes, and mechanisms) from both laboratory experiments and field observations. A suite of numerical models with fully-dynamic and hydro-mechanical coupling has been used to examine in detail the interaction between natural and induced fractures with the variations of the differential stresses and the orientations of the pre-fractures, and the relationship between the fluid front, the fracture tip, and the induced seismicity. The numerical results qualitatively agreed with the laboratory and field observations of the geometry of hydraulic fractures, confirmed the possible mechanics of new fracture development and their interactions with natural fractures, and illustrated the possible relationship between the fluid front and the fracture tip. The validated model could therefore help track the potential extent of induced fracturing in naturally-fractured reservoirs and the extent to which it can be detected by a microseismic monitoring array in order to assess the effectiveness of a hydraulic fracturing project.

In this thesis, I examine how claims regarding the environmental and health impacts of hydraulic fracturing or “fracking” are constructed by industry advocates who promote the practice and environmental and social justice groups who reject it. More specifically, I examine the cultural underpinnings of the debate over fracking, and the prominence of gender as a central framing device in that debate. While the controversy over fracking is often presented as scientific or technical in nature, I maintain that it is as much a culture war as it is a science war. I demonstrate this by showing how both pro-fracking and anti-fracking groups mobilize cultural symbols and identities—motherhood, environmentalism, family farming, family values, individualism, and patriotism among them—in order to persuade the public and advocate for their positions. I contend that engagement with the cultural and ideological dimensions of those debates, including their gendered dimensions, is as important as engagement with its scientific and technical dimensions. Ultimately, I argue that a greater focus on gender contributes to our understanding of environmental risk more broadly, and to the field of environmental sociology as a whole. As such, gender deserves more scholarly attention within the field than it is currently receiving.

“Earth, Air, Water, Oil: Regulating Fracking in the Monterey Shale with Health and Environment in Mind,” explores how hydraulic fracturing regulation in California’s oil-rich Monterey Shale will impact regional public health, including groundwater and air quality. This is achieved through a combination of case study and policy analysis on both the state and national level.

This thesis looks at the current fracking debate on a national scale, before focusing specifically on how this debate is playing out in the landscape of Central Arkansas. Focusing on the lack of national regulation, the unique array of state regulations that have popped up are assessed in their effectiveness on the ground through speaking with residents of the area. The demographics of these residents are analyzed within an assessment of environmental injustice vulnerability. This ethnographic approach also compares the de jure v. de facto outcomes of these regulations through the narratives of residents working with organizations across the political spectrum, and specifically seeks to gauge their own personal stories and experiences with regulators and the fracking industry. Other key actors are identified. This thesis concludes that agency capture is a reality for these residents, and their perceived powerlessness drastically increases the power of the gas companies that monopolize the political agenda in the region.