Browsing by Subject "Fracture propagation"
Now showing 1 - 9 of 9
- Results Per Page
- Sort Options
Item A lattice model for gas production from hydrofractured shale(2016-12) Eftekhari, Behzad; Patzek, Tadeusz W.; Marder, Michael P., 1960-; Olson, Jon E; Sepehrnoori, Kamy; Espinoza, David NNatural gas production from US shale and tight oil plays has increased over the past 10 years, currently constitutes more than half of the total US dry natural gas production, and is projected to provide the US with a major energy source in the next several decades. The increase in shale gas production is driven by advances in hydraulic fracturing. Recent studies have shown that gas production from hydraulically fractured shales has to come from a network of connected hydraulic and natural fractures, and that if one takes the shale permeability to be 10 nD, then the characteristic spacing of the fracture network will be about 1.5 − 3 m. The precise nature of the characteristic spacing, as well as other production and formation properties of the fracture network, are questions which motivated the present dissertation. This dissertation studies (1) the topology of the fracture network, (2) the mechanics of how the fracture network evolves in time during injection and (3) how fracture network geometry affects production. We use percolation theory to study fracture network topology. Fracture are placed on the bonds of a two–dimensional square lattice and follow a power law length distribution. We analytically obtain the scaling of connectivity for power law fracture networks, and numerically compute the percolation threshold as a function of the exponent. We develop a hydrofracture model which makes it possible to simulate initiation and propagation of hydraulic fractures, as well as the interaction between hydraulic and natural fractures. The model uses the Reynolds lubrication approximation to describe fluid flow through the fractures and relies on analytical estimates to predict the stress response. We develop a diffusion model to compute gas production from hydraulically fractured shales. The model uses a random walk algorithm and takes the fracture network as the absorbing boundary to the gas transport equation. We show that scaling the cumulative production versus time data from the diffusion model with respect to characteristic scales of production maps the production versus time plots onto a single scaling curve. Using the model, we identify, or define, characteristic spacing for fracture networks.Item A new reservoir scale model for fracture propagation and stress reorientation in waterflooded reservoirs(2016-12) Bhardwaj, Prateek; Sharma, Mukul M.It is now well established that poro-thermo-elastic effects substantially change the magnitude and orientation of in-situ stresses. Fractures induced in injectors during water injection for waterflooding or produced water disposal have a profound impact on waterflood performance. These effects, coupled with injectivity decline due to plugging caused by injected particles, lead to permeability reduction, fracture initiation and propagation. Models are available for fracture propagation in single injection wells and single layered reservoirs that account for these effects. However, the impact of fluid injection and production on fracture growth in multiple wells and multi-layered reservoirs with competing fractures, has not been systematically modelled at a field scale. In this work, a three-dimensional, two-phase flow simulator with iteratively coupled geomechanics has been developed and applied to model the dynamic growth of injection-induced fractures. The model is based on a finite volume implementation of the cohesive zone model for arbitrary fracture propagation coupled with two-phase flow. A dynamic filtration model for permeability reduction is employed on the fracture faces to incorporate effects of internal damage and external filter cake build-up due to the injection of suspended solids and oil droplets. All physical phenomena are solved in a single framework designed for multi-well, field-scale simulation. The pressure distribution, saturation profile, thermal front, mechanical displacements and reservoir stresses are computed as fluids are injected and produced from the reservoir. Simulation results are discussed with single as well as multiple fractures propagating. Stress reorientation due to poroelastic, thermoelastic and mechanical effects is examined for the simulated cases. The orientation of the fractures is controlled primarily by the orientation of the stresses, which in turn depends on the pattern of wells and the rates of injection and production. The sweep efficiency of the waterflood is found to be impacted by the rate of growth of injection-induced fractures. Heterogeneities in multi-layered reservoirs strongly govern the expected vertical sweep and fluid distribution, which impacts the cumulative oil recovery. This is the first time a formulation of multiphase flow in the reservoir has been coupled with dynamic fracture propagation in multiple wells induced by solids plugging while including poro-thermo-elasticity at the reservoir scale. The model developed in this work can be used to simulate multiple water injection induced fractures, determine the reoriented stress state to optimize the location of infill wells and adjust injection well patterns to maximize reservoir sweep.Item Coupled chemo-mechanical processes in reservoir geomechanics(2018-06-15) Shovkun, Igor; Espinoza, David N.; Sharma, Mukul M; Foster, John T; Balhoff, Matthew T; Hesse, Marc EReservoir geomechanics investigates the implications of rock deformation, strain localization, and failure for completion and production of subsurface energy reservoirs. For example, effective hydraulic fracture placement and reservoir pressure management are among the most important applications for maximizing hydrocarbon production. The correct use of these applications requires understanding the interaction of fluid flow and rock deformations. In the past a considerable amount of effort has been made to describe the role of poroelastic and thermal effects in geomechanics. However, a number of chemical processes that commonly occur in reservoir engineering have been disregarded in reservoir geomechanics despite their significant effect on the mechanical behavior of rocks and, therefore, fluid flow. This dissertation focuses on the mechanical effects of two particular chemical processes: gas-desorption from organic-rich rocks and mineral dissolution in carbonate-rich formations. The methods employ a combination of laboratory studies, field data analysis, and numerical simulations at various length scales. The following conclusions are the results of this work: (1) the introduced numerical model for fluid flow with effects of gas sorption and shear-failure-impaired permeability captures the complex permeability evolution during gas production in coal reservoirs; the simulation results also indicate the presence non-negligible sorption stresses in shale reservoirs, (2) mineral dissolution of mineralized fractures, similar to pore pressure depletion or thermal cooling/heating can increase stress anisotropy, which can reactivate critically-oriented natural fractures; in-situ stress chemical manipulation can be used advantageously to enlarge the stimulated reservoir volume, (3) semicircular bending experiments on acidized rock samples show that non-planar fractures follow high porosity regions and large pores, and that fracture toughness correlates well with local porosity. Numerical modeling based on the Phase-Field approach shows that a direct relationship between fracture toughness and porosity permits replicating fracture stress intensity at initiation and non-planar fracture propagation patterns observed in experiments, and (4) numerical simulations based on a novel reactive fluid flow model coupled with geomechanics show that mineral dissolution (i) lower fracture breakdown pressure, (ii) can bridge a transition from a toughness-dominated regime to uncontrolled fracture propagation at constant injection pressures, and (iii) can increase fracture complexity by facilitating propagation of stalled fracture branches. The understanding of these chemo-mechanical coupled processes is critical for safe and effective injection of CO2 and reactive fluids in the subsurface, such as in hydraulic fracturing, deep geothermal energy, and carbon geological sequestration applications.Item Coupled geomechanics and compositional fluid flow modeling for unconventional oil and gas reservoirs(2019-02-14) Gala, Deepen Paresh; Sharma, Mukul M.; Bonnecaze, Roger T; Edgar, Thomas F; Mohanty, Kishore; Ribeiro, LionelThe integration of geomechanics with multi-phase, multi-component fluid flow in porous media has several applications in the upstream oil and gas industry. It can be applied for both near wellbore and reservoir scale problems in different reservoir types. The development of a 3D geomechanics and compositional flow model coupled with fracture growth capability is presented. The partial differential equations in the reservoir, fracture and well domain are solved in a coupled manner. The model is validated/verified for different physics such as fracture growth, stress around a fracture and well, phase behavior, multiphase flow, compressible flow and poroelasticity. The model is then applied to problems specific to low permeability shale and tight reservoirs, however, the model is very general and can be applied to any subsurface hydrocarbon or water reservoir. Propagation of multiple fractures using different fluids such as slickwater, gases and foams is studied using field scale examples. The impact of variables such as fluid compressibility, viscosity, wellbore volume, reservoir permeability, stress/tensile strength ratio, and poroelasticity on fracture geometry, breakdown and shut-in behavior is investigated in detail. Production from a well and the resulting stress changes are calculated in dry gas, gas condensates, black oil and volatile oil reservoirs. Permeability changes associated with an increase in effective stress on fractures and reservoir rock are shown to have a significant impact on decline rates. The impact of water evaporation and subsequent salt precipitation on productivity in shale gas reservoirs is evaluated. A sensitivity study is performed for variables such as capillary pressure, fracture spacing, reservoir permeability, initial brine saturation, reservoir temperature and well operating BHP. A method of fluid injection (water or gas) in depleted parent wells (known as pre-loading) to minimize damage due to frac-hits is studied. The stress and pressure changes due to fluid injection are shown to be dependent on injection fluid and reservoir fluid type, injection rates and the fracture geometry in parent wells. The compositional and geomechanical effects in a Huff-n-Puff gas injection IOR process in tight oil reservoirs are investigated. The additional recovery and increase in GOR after several Huff-n-Puff cycles is shown to be a function of reservoir and injected fluid composition and hysteresis in permeability as a function of effective stress.Item The enriched Galerkin method for linear elasticity and phase field fracture propagation(2015-12) Mital, Prashant; Wheeler, Mary F. (Mary Fanett); Wick, ThomasThis thesis focuses on the application of the discontinuous Galerkin (DG) and enriched Galerkin (EG) methods to the problems of linear elasticity and phase field fracture propagation. The use of traditional and popular continuous Galerkin method (CG) for linear elasticity has posed some challenges. For example, nonphysical stress oscillations often occur in CG solutions for linearly elastic, nearly incompressible materials. Furthermore, CG solutions produce discontinuous stresses at the finite element boundaries which need to be post-processed. Based on the success of the DG methods in solving these challenges, we attempt resolution of the same problems with the yet untested EG method. For phase field fracture propagation, the CG method has been ubiquitously used in the literature. Since the phase field displacement solution is essentially discontinuous across the crack, we hypothesize that the discontinuous DG and EG methods could offer some advantages when applied to the fracture problem. We then perform a comparative analysis of CG, DG and EG applied to the phase field equations to determine if this is indeed the case. We begin by applying a family of DG and EG methods, including Nonsymmetric Interior Penalty Galerkin (NIPG), Symmetric Interior Penalty Galerkin (SIPG), and Incomplete Interior Penalty Galerkin (IIPG) to 2D linear elasticity problems. It is shown that the EG methods are simple and robust for dealing with linear elasticity. They are also shown to converge at the same rates as the corresponding DG methods. A detailed comparison of the performance of NIPG, IIPG, and SIPG is also made. We then propose a novel monolithic scheme with an augmented-Lagrangian method for phase field fracture propagation. We apply CG, DG and EG methods to the scheme and establish convergence in space and time through numerical studies. It is shown that the Newton method used for solving the system of nonlinear equations converges faster for DG and EG than it does for CG.Item Experimental studies in hydraulic fracture growth : fundamental insights and validation experiments for geomechanical models(2019-01-23) Al Tammar, Murtadha Jawad; Sharma, Mukul M.; Ravi-Chandar, Krishnas; Olson, Jon E.; Prodanović, Maša; Espinoza, David N.Novel experimental capabilities to study hydraulic fracturing in the laboratory are developed and utilized in this research. Fracturing experiments are conducted using two-dimensional (2-D) test specimens that are made from synthetic, porous materials with well-characterized properties. Fracture growth during the experiments is captured with clear, high resolution images and subsequent image processing using Digital Image Correlation (DIC) analyses. First, we investigated the problem of a hydraulic fracture induced in a soft layer bounded by harder layers. The experiments reveal a clear tendency for induced fractures to avoid harder bounding layers. This is seen as fracture deflection or kinking away from the harder layers, fracture curving between the harder bounding layers, and fracture tilt from the maximum far-field stress direction. In addition, when a fracture is induced in a relatively thin layer, the fracture avoids the harder bounding layers by initiating and propagating parallel to the bounding interfaces. Fracture propagation parallel to the bounding layers is also observed in relatively wide layers when the far-field stress is isotropic or very low. Complex fracture trajectories are induced in layered specimens when the far-field differential stress is low or intermediate. In a second set of experiments, we used homogeneous specimens with multiple fluid injection ports. It is clearly shown that injection-induced stresses can appreciably affect hydraulic fracture trajectories and fracturing pressures. We show that induced hydraulic fractures, under our laboratory conditions, are attracted to regions of high pore pressure. Induced fractures tend to propagate towards neighboring high pore pressure injection ports. The recorded breakdown pressure in the fracturing experiments decreases significantly as the number of neighboring injectors increases. The influence of an adjacent fluid injection source on the hydraulic fracture trajectory can be minimized or suppressed when the applied far-field differential stress is relatively high. Preferential fracture growth due to changes in pore pressure in field applications as compared to our laboratory observations is also discussed. In a third set of experiments, we show that the breakdown pressure of test specimens can be reduced markedly with low injection rates, cyclic borehole pressurization, and/or constant pressure injection. This is largely related to the extent of pressurized region around the borehole caused by fluid leakoff in dry specimens and possible specimen weakening by fluid contact. The breakdown pressure can also be reduced by notching the specimen borehole when the injection fluid is allowed to flow and leak off along the borehole notch. In a fourth set of experiments, we compared fracture growth induced by a viscous liquid and a gas which are glycerin and nitrogen, respectively. The experiments show that fractures propagate through test specimens in a gradual manner when induced by glycerin at various injection rates. By contrast, nitrogen injection induces fractures that grow much more rapidly, which we attribute to its compressible nature and ultralow viscosity. The breakdown pressure is also shown to be markedly lower for nitrogen fractures compared to glycerin fractures. Moreover, an experimental evidence of fluid lag when fractures are induced with viscous fluids is demonstrated. Lastly, experiments were conducted to examine the behavior of an induced hydraulic fracture as it approaches a cemented natural fracture. We show a tendency for the induced hydraulic fracture to cross thick natural fractures filled with softer materials than the host rock and to be diverted by thick natural fractures with harder filling materials. The induced hydraulic fracture also tends to cross hard natural fractures when the natural fractures are relatively thin. In addition, the induced hydraulic fracture from the injection port is shown to be diverted by a thin, hard natural fracture that is placed relatively close to the injection port but crosses the same natural fracture when placed farther away from the injection port. These observations, and numerous others, documented in this dissertation provide fundamental insights on various aspects of hydraulic fracture propagation. Our extensive set of laboratory observations are also very useful in validating numerical hydraulic fracturing simulators due to the small-scale, 2-D nature, and characterized properties of the test specimens used in the experiments.Item Lost circulation mitigation in low permeability formations using fluid additives that encourage fracture termination against pre-existing fractures(2016-01-13) Oyedere, Mayowa Olugbenga; Gray, Kenneth E., Ph. D.; McClure, Mark W. (Mark William)Lost circulation is a long-standing challenge in the petroleum industry and a major contributor to non-productive rig time during drilling. Over the years, the industry has developed various lost circulation mitigation (LCM) techniques, several of which have yielded positive results. Lost circulation remains a particular problem in formations that have very low permeability but which do not have high clay content. Low permeability formations, especially shales, often contain natural fractures. When a hydraulic fracture is induced during drilling, it may interact with these pre-existing fractures and other planes of weakness by either terminating or crossing. We investigated whether these interactions could be exploited to mitigate lost circulation. A novel hypothesis for how low matrix permeability could encourage termination through a time-dependent poroelastic effect was developed and tested using a hydraulic fracturing simulator (CFRAC). Previous studies have shown that crossing occurs when hydraulic fractures are able to reinitiate on the other side of the plane of weakness. A sensitivity study was performed to investigate the effect of permeability, tensile yield strength, and the rate of hydraulic fracture propagation on the ability for incipient fractures to initiate on the opposite side of the preexisting fracture. Results showed that in low permeability formations, a high rate of hydraulic fracture propagation may cause termination. Based on the hypothesis and the results of the sensitivity study, a semi-analytical time-dependent model to predict crossing was developed and implemented into CFRAC. CFRAC’s ability to simulate the injection of fluids with different injection rates and fluid viscosities was used to design a two-step LCM pumping sequence of high injection rate and low fluid viscosity, followed by lower injection rate and high fluid viscosity.Item Modeling flow and geomechanics in fractured reservoirs(2021-08-13) Jammoul, Mohamad; Wheeler, Mary F. (Mary Fanett); Arbogast, Todd; Balhoff, Matthew; Foster, John; Sharma, MukulSubsurface problems are inherently challenging because they involve multiple physical processes interacting with each other. Numerical models tend to break down the system into smaller problems that are easier to solve and that could be coupled within one framework. Fractured reservoirs are especially difficult to model due to the variety of physical processes that act at different scales. These processes include (1) fracture propagation, (2) flow through fractures and through the matrix, (3) hydrocarbon phase behavior, and (4) poroelastic deformations. Modeling the interaction between these processes plays an integral role in designing many energy and environmental applications. The primary objective of this work is to construct a holistic framework that can model flow and geomechanics in fractured reservoirs using computationally efficient algorithms. The framework can handle complex multiphysics problems including: multiphase flow, mechanical deformations, the capability to stimulate new fractures or activate existing ones, and the ability to seamlessly switch between propagation and production scenarios within the same simulation study. The approach includes coupling the in-house reservoir simulator (IPARS) with a phase-field fracture propagation model. In addition to hydraulic fracturing problems, the framework can model flow and geomechanics on fixed fracture networks with dynamic aperture variations. It can also simulate multiphase flow through natural fractures using general semi-structured grids. Two numerical schemes are introduced to improve the efficiency of computations. A multirate approach is proposed to enhance the performance of the L-scheme for decoupling the phase-field and displacement equations. A domain decomposition scheme is also presented to perform space-time refinement for flow through fractured reservoirs. Local time stepping and spatial mesh refinement can be used in the vicinity of the fractures while taking large grids cells with coarse time steps everywhere else in the reservoir. This motivates space and time adaptive mesh refinement in reservoir simulations.Item Modeling fracture propagation in poorly consolidated sands(2011-05) Agarwal, Karn; Sharma, Mukul M.Frac-pack design is still done on conventional hydraulic fracturing models that employ linear elastic fracture mechanics. However it has become evident that the traditional models of fracture growth are not applicable to soft rocks/unconsolidated formations due to elastoplastic material behavior and strong coupling between flow and stress model. Conventional hydraulic fracture models do not explain the very high net fracturing pressures reported in field and experiments and predict smaller fracture widths than expected. The key observations from past experimental work are that the fracture propagation in poorly consolidated sands is a strong function of fluid rheology and leak off and is accompanied by large inelastic deformation and shear failure leading to higher net fracturing pressures. In this thesis a numerical model is formulated to better understand the mechanisms governing fracture propagation in poorly consolidated sands under different conditions. The key issues to be accounted for are the low shear strength of soft rocks/unconsolidated sands making them susceptible to shear failure and the high permeabilities and subsequently high leakoff in these formations causing substantial pore pressure changes in the near wellbore region. The pore pressure changes cause poroelastic stress changes resulting in a strong fluid/solid coupling. Also, the formation of internal and external filtercakes due to plugging by particles present in the injected fluids can have a major impact on the failure mechanism and observed fracturing pressures. In the presented model the fracture propagation mechanism is different from the linear elastic fracture mechanics approach. Elastoplastic material behavior and poroelastic stress effects are accounted for. Shear failure takes place at the tip due to fluid invasion and pore pressure increase. Subsequently the tip may fail in tension and the fracture propagates. The model also accounts for reduction in porosity and permeability due to plugging by particles in the injected fluids. The key influence of pore pressure gradients, fluid leakoff and the elastic and strength properties of rock on the failure mechanisms in sands have been demonstrated and found to be consistent with experimental observations.