Many hydraulically fractured shale gas horizontal wells in the Barnett shale have been observed to exhibit transient linear behavior. This transient linear behavior is characterized by a one-half slope on a log-log plot of rate against time. This transient linear flow regime is believed to be caused by transient drainage of low permeability matrix blocks into adjoining fractures. This transient flow regime is the only flow regime available for analysis in many wells. The hydraulically fractured shale gas reservoir system was described in this work by a linear dual porosity model. This consisted of a bounded rectangular reservoir with slab matrix blocks draining into adjoining fractures and subsequently to a horizontal well in the centre. The horizontal well fully penetrates the rectangular reservoir. Convergence skin is incorporated into the linear model to account for the presence of the horizontal wellbore. Five flow regions were identified with this model. Region 1 is due to transient flow only in the fractures. Region 2 is bilinear flow and occurs when the matrix drainage begins simultaneously with the transient flow in the fractures. Region 3 is the response for a homogeneous reservoir. Region 4 is dominated by transient matrix drainage and is the transient flow regime of interest. Region 5 is the boundary dominated transient response. New working equations were developed and presented for analysis of Regions 1 to 4. No equation was presented for Region 5 as it requires a combination of material balance and productivity index equations beyond the scope of this work. It is concluded that the transient linear region observed in field data occurs in Region 4 – drainage of the matrix. A procedure is presented for analysis. The only parameter that can be determined with available data is the matrix drainage area, Acm. It was also demonstrated in this work that the effect of skin under constant rate and constant bottomhole pressure conditions is not similar for a linear reservoir. The constant rate case is the usual parallel lines with an offset but the constant bottomhole pressure shows a gradual diminishing effect of skin. A new analytical equation was presented to describe the constant bottomhole pressure effect of skin in a linear reservoir. It was also demonstrated that different shape factor formulations (Warren and Root, Zimmerman and Kazemi) result in similar Region 4 transient linear response provided that the appropriate f(s) modifications consistent with lAc calculations are conducted. It was also demonstrated that different matrix geometry exhibit the same Region 4 transient linear response when the area-volume ratios are similar.

With the growing interest in low-permeability gas plays, foam fracturing fluids are now well established as a viable alternative to traditional fracturing fluids. Present practices in energized fracturing treatments remain nonetheless rudimentary in comparison to other fracturing fluid technologies because of our limited understanding of multi-phase fluid-loss and phase behavior occurring in these complex fluids. This report assesses the fluid-loss benefits introduced by energizing the fracturing fluid. A new laboratory apparatus has been specifically designed and built for measuring the leak-off rates for both gas and liquid phases under dynamic fluid-loss conditions. This report provides experimental leak-off results for linear guar gels and for N2-guar foam-based fracturing fluids under a wide range of fracturing conditions. In particular, the effects of the rock permeability, the foam quality, and the pressure drop are investigated. Analysis of dynamic leak-off data provide an understanding of the complex mechanisms of viscous invasion and filter-cake formation occurring at the pore-scale. This study presents data supporting the superior fluid-loss behavior of foams, which exhibit minor liquid invasion and limited damage. It also shows direct measurements of the ability of the gas component to leak-off into the invaded zone, thereby increasing the gas saturation around the fracture and enhancing the gas productivity during flowback. Our conclusions not only confirm, but add to the findings of McGowen and Vitthal (1996) for linear gels, and the findings of Harris (1985) for nitrogen foams. / text

Texas water resources are under pressure due to population growth expected in the coming decades, increasing industrial demands, and frequent periods of drought. With this increasing demand for limited water resources it is important to explore alternative water sources within the State. One of those resources that can be developed is the many small aquifers which have never been well-characterized but could be an alternative source of fresh and brackish water for agriculture, municipal, and industrial applications. The natural gas industry’s demand for water is growing in Texas as new drilling techniques such a hydraulic fracturing have opened new reserves previously considered economically non-viable. The development of smaller aquifers containing brackish water is a viable alternative to the gas industry’s current reliance on fresh (potable) groundwater resources. The aquifer sections containing brackish water need to be mapped and characterized so they can be developed as an alternative water resource by the gas industry. The Barnett Shale in North-central Texas is one of the first major gas plays in the United States to use the technique of hydraulic fracturing in field development. This technique requires large quantities of water to create the required hydraulic pressure down the gas well to fracture the normally low permeability shale. A typical horizontal well completion consumes approximately 3.0 to 3.5 million gallons (11,400 to 13,200 m3) of fresh water. Projections of future groundwater demand for the Barnett Shale gas play total 417,000 AF (5.1x108 m3), an annual average of 22,000 AF (2.7x107 m3) over the expected 2007-2025 development phase. This level of water demand has the gas industry and groundwater managers exploring alternative sources of water for future development of the Barnett Shale. One alternative source of water for the expanding footprint of the Barnett Shale gas play are the smaller local Paleozoic aquifers on the western edge of the play. These small aquifers are underutilized and contain waters with higher levels of TDS. These levels are, however, acceptable to the drilling industry. In order to characterize theses aquifers, TWDB databases were utilized to analyze water chemistry and well productivity. / text

It is essential to understand natural fracture systems embedded in shale-gas reservoirs and the stress fields that influence how induced fractures form in targeted shale units. Multicomponent seismic technology and elastic seismic stratigraphy allow geologic formations to be better images through analysis of different S-wave modes as well as the P-wave mode. Significant amounts of energy produced by P-wave sources radiate through the Earth as downgoing SV-wave energy. A vertical-force source is an effective source for direct SV radiation and provides a pure shear-wave mode (SV-SV) that should reveal crucial information about geologic surfaces located in anisotropic media. SV-SV shear wave modes should carry important information about petrophysical characteristics of hydrocarbon systems that cannot be obtained using other elastic-wave modes. Regardless of the difficulties of extracting good-quality SV-SV signal, direct shear waves as well as direct P and converted S energy should be accounted for in 3C seismic studies. Acquisition of full-azimuth seismic data and sampling data at small intervals over long offsets are required for detailed anisotropy analysis. If 3C3D data can be acquired with improved signal-to-noise ratio, more uniform illumination of targets, increased lateral resolution, more accurate amplitude attributes, and better multiple attenuation, such data will have strong interest by the industry. The objectives of this research are: (1) determine the feasibility of extracting direct SV-SV common-mid-point sections from 3-C seismic surveys, (2) improve the exploration for stratigraphic traps by developing systematic relationship between petrophysical properties and combinations of P and S wave modes, (3) create compelling examples illustrating how hydrocarbon-bearing reservoirs in low-permeable rocks (particularly anisotropic shale formations) can be better characterized using different S-wave modes (P-SV, SV-SV) in addition to the conventional P-P modes, and (4) analyze P and S radiation patterns produced by a variety of seismic sources. The research done in this study has contributed to understanding the physics involved in direct-S radiation from vertical-force source stations. A U.S. Patent issued to the Board of Regents of the University of Texas System now protects the intellectual property the Exploration Geophysics Laboratory has developed related to S-wave generation by vertical-force sources. The University’s Office of Technology Commercialization is actively engaged in commercializing this new S-wave reflection seismic technology on behalf of the Board of Regents. / text

The growing demand for energy provides an incentive to pursue unconventional resources. Among these resources, tight gas and shale gas reservoirs have gained significant momentum because recent advances in technology allowed us to produce them at an economical rate. More importantly, they seem likely to contain a significant volume of hydrocarbon. There are, however, many questions concerning hydrocarbon production from these unconventional resources. For instance, in tight gas sandstone, we observe a significant variability in the producibilities of wells in the same field. The heterogeneity is even present in a single well with changes in depth. It is not clear what controls this heterogeneity. In shale gas, the pore connectivity inside the void space is not well explored and hence, a representative pore model is not available. Further, the effects of an adsorbed layer of gas and gas slippage on shale permeability are poorly understood. These effects play a crucial role in assigning a realistic permeability for shale in-situ from a laboratory measurement. In the laboratory, in contrast to in-situ, the core sample lacks the adsorbed layer because the permeability measurements are typically conducted at small pore pressures. Moreover, the gas slippages in laboratory and in-situ conditions are not identical. The present study seeks to investigate these discrepancies. Drainage and imbibition are sensitive to pore connectivity and unconventional gas transport is strongly affected by the connectivity. Hence, there is a strong interest in modeling mercury intrusion capillary pressure (MICP) test because it provides valuable information regarding the pore connectivity. In tight gas sandstone, the main objective of this research is to find a relationship between the estimated ultimate recovery (EUR) and the petrophysical properties measured by drainage/imbibition tests (mercury intrusion, withdrawal, and porous plate) and by resistivity analyses. As a measure of gas likely to be trapped in the matrix during production---and hence a proxy for EUR---we use the ratio of residual mercury saturation after mercury withdrawal (S[subscript gr]) to initial mercury saturation (S[subscript gi]), which is the saturation at the start of withdrawal. Crucially, a multiscale pore-level model is required to explain mercury intrusion capillary pressure measurements in these rocks. The multiscale model comprises a conventional network model and a tree-like pore structure (an acyclic network) that mimic the intergranular (macroporosity) and intragranular (microporosity) void spaces, respectively. Applying the multiscale model to porous plate data, we classify the pore spaces of rocks into macro-dominant, intermediate, and micro-dominant. These classes have progressively less drainage/imbibition hysteresis, which leads to the prediction that significantly more hydrocarbon is recoverable from microporosity than macroporosity. Available field data (production logs) corroborate the higher producibility of the microporosity. The recovery of hydrocarbon from micro-dominant pore structure is superior despite its inferior initial production (IP). Thus, a reservoir or a region in which the fraction of microporosity varies spatially may show only a weak correlation between IP and EUR. In shale gas, we analyze the pore structure of the matrix using mercury intrusion data to provide a more realistic model of pore connectivity. In the present study, we propose two pore models: dead-end pores and Nooks and Crannies. In the first model, the void space consists of many dead-end pores with circular pore throats. The second model supposes that the void space contains pore throats with large aspect ratios that are connected through the rock. We analyze both the scanning electron microscope (SEM) images of the shale and the effect of confining stress on the pore size distribution obtained from the mercury intrusion test to decide which pore model is representative of the in-situ condition. We conclude that the dead-end pores model is more representative. In addition, we study the effects of adsorbed layers of CH₄ and of gas slippage in pore walls on the flow behavior in individual conduits of simple geometry and in networks of such conduits. The network is based on the SEM image and drainage experiment in shale. To represent the effect of adsorbed gas, the effective size of each throat in the network depends on the pressure. The hydraulic conductance of each throat is determined based on the Knudsen number (Kn) criterion. The results indicate that laboratory measurements made with N₂ at ambient temperature and 5-MPa pressure, which is typical for the transient pulse decay method, overestimate the gas permeability in the early life of production by a factor of 4. This ratio increases if the measurement is run at ambient conditions because the low pressure enhances the slippage and reduces the thickness of the adsorbed layer. Moreover, the permeability increases nonlinearly as the in-situ pressure decreases during production. This effect contributes to mitigating the decline in production rates of shale gas wells. Laboratory data available in the literature for methane permeability at pressures below 7 MPa agree with model predictions of the effect of pressure. / text

The Fayetteville Shale is composed dominantly of clay, carbonate, and siliciclastic minerals. A variety of facies have been described by other workers and in this study, defined by mineral content, biota, fabric, and texture. Because the Fayetteville Shale is one of the top shale-gas producing plays in the U.S., an inquiry into key drivers of good-quality production is worthwhile. In particular, a hypothesis that intervals of high clay content should be avoided as production targets is investigated in this study. A high level of separation between wire-line log neutron porosity (NPHI) and density porosity (DPHI) in the Fayetteville Shale is observed in contrast to the wire-line log responses from the Barnett and Haynesville Shales. Clay minerals have a significant effect on NPHI, which in turn affects separation between NPHI and DPHI (PHISEP). X-Ray Diffraction (XRD) clay data was available for three wells, and efforts to correlate XRD results to PHISEP led to establishing NPHI as a reasonable proxy for clay. Using NPHI as a proxy it was possible to pick clay-rich intervals, map them across the study area, and to determine net clay in the Fayetteville Shale. Maps of net clay-rich intervals were compared to a map of production, but revealed no obvious correlation. Stratigraphic cross-sections showing the clay-rich intervals revealed a clay-poor interval in the upper part of the lower Fayetteville. This interval is the primary target for horizontal well completion. It is bounded above and below by more clay-rich intervals. Establishing the clay-rich intervals via porosity log separation (PHISEP) is one tool to help determine possible stratigraphic zones of gas production and can lead to a better understanding of intervals in which to expect production. / text

The Marcellus Shale is an important resource play prevalent in several states in the eastern United States. The productive zone of the Marcellus Shale has variations in rock properties such as clay content, kerogen content and pore aspect ratio, and these variations may strongly effect elastic anisotropy. The objective of this study is to characterize surface seismic sensitivity for variations in anisotropic parameters relating to kerogen content and aspect ratio of kerogen saturated pores. The recognized sensitivity may aid to characterize these reservoir from surface seismic observations for exploration and production of hydrocarbon. In this study, I performed VTI anisotropic modeling based on geophysical wireline log data from Harrison County, WV. The wireline log data includes spectral gamma, density, resistivity, neutron porosity, monopole and dipole sonic logs. Borehole log data were analyzed to characterize the Marcellus Shale interval, and quantify petrophysical properties such as clay content, kerogen content and porosity. A rock physics model was employed to build link between petrophysical properties and elastic constants. The rock physics model utilized differential effective medium (DEM) theory, bounds and mixing laws and fluid substitution equations in a model scheme to compute elastic constants for known variations in matrix composition, kerogen content and pore shape distribution. The seismic simulations were conducted applying a vertical impulse source and three component receivers. The anisotropic effect to angular amplitude variations for PP, PS and SS reflections were found to be dominantly controlled by the Thomsen Ɛ parameter, characterizing seismic velocity variations with propagation direction. These anisotropic effect to PP data can be seen at large offset (>15o incidence angle). The most sensitive portion of PS reflections was observed at mid offset (15o-30o). I also analyzed seismic sensitivity for variations in kerogen content and aspect ratio of structural kerogen. Elastic constants were computed for 5%, 10%, 20% and 30% kerogen content from rock physics model and provided to the seismic model. For both kerogen content and aspect ratio model, PP amplitudes varies significantly at zero to near offset while PS amplitude varied at mid offsets (12 to 30 degree angle of incidences). / text

Successful creations of multiple hydraulic fractures in horizontal wells are critical for economic development of unconventional reservoirs. The recent advances in diagnostic techniques suggest that multi-fracturing stimulation in unconventional reservoirs has often caused complex fracture geometry. The most important factors that might be responsible for the fracture complexity are fracture interaction and the intersection of the hydraulic and natural fracture. The complexity of fracture geometry results in significant uncertainty in fracturing treatment designs and production optimization. Modeling complex fracture propagation can provide a vital link between fracture geometry and stimulation treatments and play a significant role in economically developing unconventional reservoirs. In this research, a novel fracture propagation model was developed to simulate complex hydraulic fracture propagation in unconventional reservoirs. The model coupled rock deformation with fluid flow in the fractures and the horizontal wellbore. A Simplified Three Dimensional Displacement Discontinuity Method (S3D DDM) was proposed to describe rock deformation, calculating fracture opening and shearing as well as fracture interaction. This simplified 3D method is much more accurate than faster pseudo-3D methods for describing multiple fracture propagation but requires significantly less computational effort than fully three-dimensional methods. The mechanical interaction can enhance opening or induce closing of certain crack elements or non-planar propagation. Fluid flow in the fracture and the associated pressure drop were based on the lubrication theory. Fluid flow in the horizontal wellbore was treated as an electrical circuit network to compute the partition of flow rate between multiple fractures and maintain pressure compatibility between the horizontal wellbore and multiple fractures. Iteratively and fully coupled procedures were employed to couple rock deformation and fluid flow by the Newton-Raphson method and the Picard iteration method. The numerical model was applied to understand physical mechanisms of complex fracture geometry and offer insights for operators to design fracturing treatments and optimize the production. Modeling results suggested that non-planar fracture geometry could be generated by an initial fracture with an angle deviating from the direction of the maximum horizontal stress, or by multiple fracture propagation in closed spacing. Stress shadow effects are induced by opening fractures and affect multiple fracture propagation. For closely spaced multiple fractures growing simultaneously, width of the interior fractures are usually significantly restricted, and length of the exterior fractures are much longer than that of the interior fractures. The exterior fractures receive most of fluid and dominate propagation, resulting in immature development of the interior fractures. Natural fractures could further complicate fracture geometry. When a hydraulic fracture encounters a natural fracture and propagates along the pre-existing path of the natural fracture, fracture width on the natural fracture segment will be restricted and injection pressure will increase, as a result of stress shadow effects from hydraulic fracture segments and additional closing stresses from in-situ stress field. When multiple fractures propagate in naturally fracture reservoirs, complex fracture networks could be induced, which are affected by perforation cluster spacing, differential stress and natural fracture patterns. Combination of our numerical model and diagnostic methods (e.g. Microseismicity, DTS and DAS) is an effective approach to accurately characterize the complex fracture geometry. Furthermore, the physics-based complex fracture geometry provided by our model can be imported into reservoir simulation models for production analysis. / text

The thesis research examined localized socio-environmental perceptions related to amplified fresh water requirements for hydraulic fracturing and subsequent flowback disposal activities. These requirements are associated with increasing shale gas development in the Duvernay formation, located within the Kaybob region of West-central Alberta, Canada. Fresh water refers to surface and groundwater with a total dissolved solids concentration of less than 4,000 ppm. Through recourse to a mixed methods approach, combined with triangulation as a method of further validation, the research demonstrates that there exists a public sensitivity related to fresh water use in the Kaybob region. This sensitivity arises from increasing development activities in the Duvernay shale gas formation. The thesis presents conclusions and recommendations whereby industry may address stakeholder concerns, and provides advice for future research.

Unconventional reservoirs are typically characterized by very low permeabilities, and thus, the pressure depletion from a producing well may not propagate far from the well during the life of a development. Currently, two approaches are widely utilized to perform unconventional reservoir analysis: analytical techniques, including the decline curve analysis and the pressure/rate transient analysis, and numerical simulation. The numerical simulation can rigorously account for complex well geometry and reservoir heterogeneity but also is time consuming. In this thesis, we propose and apply an efficient technique, fast marching method (FMM), to analyze the shale gas reservoirs. Our proposed approach stands midway between analytic techniques and numerical simulation. In contrast to analytical techniques, it takes into account complex well geometry and reservoir heterogeneity, and it is less time consuming compared to numerical simulation. The fast marching method can efficiently provide us with the solution of the pressure front propagation equation, which can be expressed as an Eikonal equation. Our approach is based on the generalization of the concept of depth of investigation. Its application to unconventional reservoirs can provide the understanding necessary to describe and optimize the interaction between complex multi-stage fractured wells, reservoir heterogeneity, drainage volumes, pressure depletion, and well rates. The proposed method allows rapid approximation of reservoir simulation results without resorting to detailed flow simulation, and also provides the time-evolution of the well drainage volume for visualization. Calibration of reservoir models to match historical dynamic data is necessary to increase confidence in simulation models and also minimize risks in decision making. In this thesis, we propose an integrated workflow: applying the genetic algorithm (GA) to calibrate the model parameters, and utilizing the fast marching based approach for forward simulation. This workflow takes advantages of both the derivative free characteristics of GA and the speed of FMM. In addition, we also provide a novel approach to incorporate the micro-seismic events (if available) into our history matching workflow so as to further constrain and better calibrate our models.