Unconventional gas has become an important resource to help meet our future energy demands. Although plentiful, it is difficult to produce this resource, when locked in a massive sedimentary formation. Among all unconventional gas resources, tight gas sands represent a big fraction and are often characterized by very low porosity and permeability associated with their producing formations, resulting in extremely low production rate. The low flow properties and the recovery factors of these sands make necessary continuous efforts to reduce costs and improve efficiency in all aspects of drilling, completion and production techniques. Many of the recent improvements have been in well completions and hydraulic fracturing. Thus, the main goal of a hydraulic fracture is to create a long, highly conductive fracture to facilitate the gas flow from the reservoir to the wellbore to obtain commercial production rates. Fracture conductivity depends on several factors, such as like the damage created by the gel during the treatment and the gel clean-up after the treatment. This research is focused on predicting more accurately the fracture conductivity, the gel damage created in fractures, and the fracture cleanup after a hydraulic fracture treatment under certain pressure and temperature conditions. Parameters that alter fracture conductivity, such as polymer concentration, breaker concentration and gas flow rate, are also examined in this study. A series of experiments, using a procedure of “dynamical fracture conductivity test”, were carried out. This procedure simulates the proppant/frac fluid slurries flow into the fractures in a low-permeability rock, as it occurs in the field, using different combinations of polymer and breaker concentrations under reservoirs conditions. The result of this study provides the basis to optimize the fracturing fluids and the polymer loading at different reservoir conditions, which may result in a clean and conductive fracture. Success in improving this process will help to decrease capital expenditures and increase the production in unconventional tight gas reservoirs.

Hydraulic Fracturing is a technique to accelerate production and enhance ultimate recovery of oil and gas while fracture geometry is an important aspect in hydraulic fracturing design and optimization. Systematic design procedures are available based on the so-called two-dimensional models (2D) focus on the optimization of fracture length and width, assuming one can estimate a value for fracture height, while so-called pseudo three dimensional (p-3D) models suitable for multi-layered reservoirs aim to maximize well production by optimizing fracture geometry, including fracture height, half-length and width at the end of the stimulation treatment. The proposed p-3D approach to design integrates four parts: 1) containment layers discretization to allow for a range of plausible fracture heights, 2) the Unified Fracture Design (UFD) model to calculate the fracture half-length and width, 3) the PKN or KGD models to predict hydraulic fracture geometry and the associated net pressure and other treatment parameters, and, finally, 4) Linear Elastic Fracture Mechanics (LEFM) to calculate fracture height. The aim is to find convergence of fracture height and net pressure. Net pressure distribution plays an important role when the fracture is propagating in the reservoir. In multi-layered reservoirs, the net pressure of each layer varies as a result of different rock properties. This study considers the contributions of all layers to the stress intensity factor at the fracture tips to find the final equilibrium height defined by the condition where the fracture toughness equals the calculated stress intensity factor based on LEFM. Other than maximizing production, another obvious application of this research is to prevent the fracture from propagating into unintended layers (i.e. gas cap and/or aquifer). Therefore, this study can aid fracture design by pointing out: (1) Treating pressure needed to optimize fracture geometry, (2) The containment top and bottom layers of a multi-layered reservoir, (3) The upwards and downwards growth of the fracture tip from the crack center.

Hydraulic fracturing is an important method used to enhance the recovery of oil and gas from reservoirs, especially for low permeability formations. The distribution of pressure in fractures and fracture geometry are needed to design conventional and unconventional hydraulic fracturing operations, fracturing during water-flooding of petroleum reservoirs, shale gas, and injection/extraction operation in a geothermal reservoir. Designing a hydraulic fracturing job requires an understanding of fracture growth as a function of treatment parameters. There are various models used to approximately define the development of fracture geometry, which can be broadly classified into 2D and 3D categories. 2D models include, the Perkins-Kern-Nordgren (PKN) fracture model, and the Khristianovic-Geertsma-de. Klerk (KGD) fracture model, and the radial model. 3D models include fully 3D models and pseudo-three-dimensional (P-3D) models. The P-3D model is used in the oil industry due to its simplification of height growth at the wellbore and along the fracture length in multi-layered formations. In this research, the Perkins-Kern-Nordgren (PKN) fracture model is adopted to simulate hydraulic fracture propagation and recession, and the pressure changing history. Two different approaches to fluid leak-off are considered, which are the classical Carter's leak-off theory with a constant leak-off coefficient, and Pressure-dependent leak-off theory. Existence of poroelastic effect in the reservoir is also considered. By examining the impact of leak-off models and poroelastic effects on fracture geometry, the influence of fracturing fluid and rock properties, and the leak-off rate on the fracture geometry and fracturing pressure are described. A short and wide fracture will be created when we use the high viscosity fracturing fluid or the formation has low shear modulus. While, the fracture length, width, fracturing pressure, and the fracture closure time increase as the fluid leak-off coefficient is decreased. In addition, an algorithm is developed for the post-fracture pressure-transient analysis to calculate formation permeability. The impulse fracture pressure transient model is applied to calculate the formation permeability both for the radial flow and linear fracture flow assumption. Results show a good agreement between this study and published work.

The recent success in economical production of US shales and other low permeability reservoirs is primarily due to advances in hydraulic fracturing. In this well stimulation technique, a fracturing fluid is injected into the reservoir at pressures high enough to break down the reservoir rock and form fractures. The fractures drain the hydrocarbons in the rock matrix and provide connected pathways for the transport of hydrocarbons to the wellbore. Given the low permeability of the matrix, recent studies of shale gas production suggest that nearly all of the production has to come from a ramified, well-connected network of fractures. A recent study has shown, however, that for reasons yet unknown, the production history of more than 8000 wells in the Barnett Shale can be fit with reasonable accuracy with a linear flow model based on parallel planar hydraulic fractures perpendicular to the wellbore and spaced 1-2 meters apart. The current study is carried out to provide insights into the formation and production properties of complex hydraulic fracture networks. The end goal here is optimization of hydraulic fracture treatments: creating better-connected, more productive fracture networks that can drain the reservoir more quickly. The study provides a mechanistic model of how complexity can emerge in the pattern of hydraulic fracture networks, and describes production from such networks. Invasion percolation has been used in this study to model how the pattern of hydraulic fracture networks develop. The algorithm was chosen because it allows quick testing of different “what if” scenarios while avoiding the high computation cost associated with numerical methods such as the finite element method. The rules that govern the invasion are based on a proposed geo-mechanical model of hydraulic fracture-natural fracture interactions. In the geo-mechanical model, development of fracture networks is modeled as a sequence of basic geo-mechanical events that take place as hydraulic fractures grow and interact with natural fractures. Analytical estimates are provided to predict the occurrence of each event. A complex network of connected fractures is the output of the invasion percolation algorithm and the geo-mechanical model. To predict gas production from the network, this study uses a random walk algorithm. The random walk algorithm was chosen over other numerical methods because of its advantage in handling the complex boundary conditions present in the problem, simplicity, accuracy and speed. / text

The effect of coupled thermo-poroelastic behavior on hydraulic fracture propagation is of much interest in geothermal- and petroleum-related geomechanics problems such as wellbore stability and hydraulic fracturing as pore pressure and temperature variations can significantly induce rock deformation, fracture initiation, and propagation. In this dissertation, a two-dimensional (2D) boundary element method (BEM) was developed to simulate the fully coupled thermo-poroelastic fracture propagation process. The influence of pore pressure and temperature changes on the fracture propagation length and path, as well as on stress and pore pressure distribution near wellbores and fractures, was considered in isotropic and homogeneous rock formations. The BEM used in this work consists of the displacement discontinuity (DD) method and the fictitious stress (FS) method. Also, a combined FS-DD numerical model was implemented for the hydraulically or thermally-induced fractures in the vicinity of a wellbore. The linear elastic fracture mechanics (LEFM) theory was adopted to numerically model within the framework of poroelasticity and thermo-poroelasticity theory. For high accuracy of crack tip modeling, a special displacement discontinuity tip element was developed and extended to capture the pore pressure and temperature influence at the tip. For poroelastic fracture propagation, a steadily propagating crack driven by fluid pressure was modeled to find the effect of pore pressure on crack path under the two limiting poroelastic conditions (undrained and drained). The results indicate that the pore pressure diffusion has no influence on the crack growth under the undrained condition because the crack propagation velocity is too fast for the diffusion effect to take place. On the other hand, its influence on the crack path under the drained condition with its low propagation velocity has significance because it induces a change in principal stress direction, resulting in an alteration of fracture orientation. For the thermal fracturing, when the rock around a wellbore and a main fracture is cooled by injecting cold water in a hot reservoir, the rapid decrease in temperature gives rise to thermal stress, which causes a crack to initiate and propagate into the rock matrix. The single and multiple fracture propagation caused by transient cooling in both thermoelastic and poro-thermoelastic rock were numerically modeled. The results of this study indicate that the thermal stresses induced by cooling may exceed the in-situ stress in the reservoir, creating secondary fractures perpendicular to main fracture. Furthermore, the faster cooling rate produces longer crack extension of the secondary thermal fractures. This implies that the faster cooling induces a higher tensile stress zone around the fracture, which tends to produce larger driving forces to make the secondary fractures penetrate deeper into the geothermal reservoir.

This dissertation focuses mainly on three topics: (1) mixed-mode branching and segmentation of hydraulic fractures in brittle materials, (2) hydraulic fracture propagation in particulate materials, and (3) hydraulic fracturing in water flooding conditions. Mixed-mode loading is one of the primary causes of fracture branching and segmentation in brittle materials. We conducted the first laboratory experiments on the mixed mode I+III hydraulic fracturing. We found that a KIII/KI ratio as small as ~1% is sufficient for fracture front segmentation. In reality, such a small mode III component is always expected, for example, due to the small deviations of the fracture shape from planar. Thus, we concluded that fracture segmentation is likely to accompany growth of most, if not all, real hydraulic fractures. We also proposed a theoretical model that captures the main features of experimental observations and indicates the importance of the hydraulic effect of segmentation. Particulate materials often exhibit pronounced non-linear behavior and yielding even at relatively small loads. In order to adequately describe hydraulic fracturing in particulate materials with low or no cohesion, plasticity at the crack tip must be explicitly considered. We investigated the shear band mechanism of strain localization at the fracture front. This mechanism takes into account the fact that cohesionless material can not bear tension, and is in compression everywhere, including near the fracture front. To verify the shear band hypothesis, we conducted numerical simulations of the plastic deformation at the tip of a fracture in particulate material with strain softening. Our model describes the shear bands by properly placed and oriented dislocations. The model results are consistent with experimental observations. Water flooding, which in certain important cases, can result in processes resembly hydraulic fracturing by a low-viscosity fluid with extremely high leak-off. It is difficult to simulate this process in the laboratory. To investigate the fracture initiation mechanism in water flooding conditions, we conducted a numerical simulation of fluid injection into particulate material by using the discrete element code PFC2D. We also considered an analytical model of cavity initiation based on the fluidization mechanism. The estimates given by this model fit remarkably well with the numerical simulation results.

Hydraulic fracturing is an important stimulation method for producing unconventional gas reserves. Natural fractures are present in many low-permeability gas environments and often provide important production pathways for natural gas. The production benefit from natural fractures can be immense, but it is difficult to quantify. The Mesaverde Group in the Piceance Basin in Colorado is a gas producing reservoir that has low matrix permeability but is also highly naturally fractured. Wells in the Piceance Basin are hydraulically fractured, so the production enhancements due to natural fracturing and hydraulic fracturing are difficult to decouple. In this thesis, dipole sonic logs were used to quantify geomechanical properties by combining stress equations with critically-stressed faulting theory. The properties derived from this log-based evaluation were used to numerically model hydraulic fracture treatments that had previously been pumped in the basin. The results from these hydraulic fracture models, in addition to the log-derived reservoir properties were used to develop reservoir models. Several methods for simulating the reservoir were compared and evaluated, including layer cake models, geostatistical models, and models simulating the fracture treatment using water injection. The results from the reservoir models were compared to actual production data to quantify the effect of both hydraulic fractures and natural fractures on production. This modeling also provided a framework upon which completion techniques were economically evaluated. / 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

Discontinuous planes often develop in soils; examples include shear bands, desiccation cracks, polygonal faults, and hydraulic fractures. These discontinuities affect the mechanical behavior (stiffness and strength) and transport properties of sediments (fluid migration and diffusion). Contrary to discontinuities in solid materials, granular materials such as soils are already separated at the particle scale. Therefore, the fundamental understanding of the development of discontinuities in soils must recognize their inherent granular nature and effective-stress dependent behavior. This research focuses on particle-scale mechanisms involved in contraction-driven shear failure due to mineral dissolution, desiccation cracks, and hydraulic fractures. Complementary experimental, analytical and numerical methods are used to study three cases. Contraction-driven polygonal fault formation under the seabed. Shear failure planes are often found in sediments that formed under near horizontal burial conditions. Particle-scale volume contraction due to mineral dissolution causes a decrease in the state of stress from the insitu K0-condition to the active failure Ka stress field. Shear strain localization follows in sediment with post-peak strain softening response. Desiccation cracks in saturated fine soils. The formation of desiccation cracks in soils is often interpreted in terms of tensile strength, which contradicts the cohesionless, effective stress dependent frictional behavior of fine grained soils. Experimental results monitored using high resolution time lapse photography point to a proper effective stress-dependent mechanism centered on the invasion of the air-water interface membrane. Miscible and immiscible fluid-driven fracture formation. Hydraulic fracture in granular materials cause grain separation and the development of conduits for preferential fluid flow leading to fracture formation due to the forced invasion of either immiscible or miscible fluids. Capillary, seepage, and skeletal interparticle forces define particle scale mechanisms at the fracture tip. Numerical simulations confirm that the effective stress remains in compression everywhere throughout the granular medium in the three localization mechanisms.

Understanding the mechanisms that govern hydraulic fracturing applications in unconventional formations, such as gas-bearing shales, is of increasing interest to the petroleum upstream industry. Among such mechanisms, the geomechanical interactions between hydraulic fractures and pre-existing fractures on one hand, and simultaneous multiple hydraulic fractures on the other hand are seen of high importance. Although the petroleum engineering and related literature contains a number of studies that discusses such topics of hydraulic fracture interactions, there still remain some aspects that require answers, validations, or further supporting data. Particularly, experimental evidence is fairly scarce and keenly needed to solidify the understanding of such complex applications. In this work, the investigation methodology uses a series of hydraulic fracturing laboratory tests performed on synthetic rocks made of gypsum-based cements such as hydrostone and plaster in various experimental set ups. Those laboratory tests aim to closely investigate hydraulic fracture intersection with pre-existing fractures by assessing some factors that govern its outcomes. Specifically, the roles of the pre-existing fracture cementation, aperture, and relative height on the intersection mode are examined. The results show dominant effect of the cement-fill type relative to the host-rock matrix in determining whether hydraulic fracture crossing the pre-existing interface may occur. Similarly, hydraulic fracture height relative to the height of the pre-existing fracture may dictate the intersection results. However, the intersection mode seems to be insensitive of the pre-existing fracture aperture. Moreover, simultaneous multi-fracture propagation is examined and found to be impacted by the interference of the stresses induced from each fracturing source on neighboring fracturing sources. Such stress interference increases as the number of the propagating hydraulic fractures increase. While hydraulic fractures initiating from fracturing sources located in the middle of the fracturing stage seem to have inhibited propagation, outer hydraulic fractures may continue propagating with outward curvatures. Overall, the experimental results and analyses offer more insights for understanding hydraulic fracture complexity in unconventional formations. / text