The basic idea behind this research is to propose a work flow to model gas flow in numerical simulators, which would take into consideration all the complexities of the multiple porosity systems that exist in shale matrix and the different dynamics of flow involved within them. The concept of a multi porosity system that is composed of the organic part (kerogen), inorganic matter, and natural and hydraulic fractures is used here. Kerogen is very different from other shale components because of its highly porous nature, capability to adsorb gas and abundance of nano-pores on its surface. Some theories have been put forward for the physics involved in shale on a micro scale level. However, when working with reservoir scale models, the details as described for porosity systems in micro scale models is lost. To overcome this problem, the idea of dynamic apparent permeability, which is a function of matrix pressure, is used. It helps in up-scaling the particulars of the micro scale model to a reservoir one and aids in modelling Darcy flow, Fickian diffusion and transition flow in between the matrix and fractures. Our assumptions are validated by working with the case of a horizontal well model, producing gas from the Barnett shale formation, that doesn't take into consideration the relevant flow phenomenon. History matching the model after integrating diffusion and desorption reveals that considering these additional processes impacts the assumed SRV region, affecting its volume as well as its properties. This would be a critical factor in optimizing completion design, to lower down the well cost for same or ever greater production. Similarly, this can play a vital role in well spacing for effective field development. We summarize our findings from production forecasts that matrix contribution towards production is under estimated when relevant assumptions for shale are not modelled. This signifies the importance of better understating the transport phenomenon occurring in shale, which would enable us to have a greater insight to scrutinize production data and later to predict changes in production as completion methods are changed. This means that a multi stage high density fracturing job might not optimize the well in terms of its value. Decreasing our expenditure on well completions, such that their design results in lower production rates at the initial time period along with lower decline rates, would enable us to produce these wells longer for the same recovery. This would enable us to push the production in future where oil and gas prices might be better. The electronic version of this dissertation is accessible from http://hdl.handle.net/1969.1/155074

Gas production from unconventional reservoirs such as gas shale and coalbed methane (CBM) has become a major source of clean energy in the United States. Reservoir apparent permeability is a critical and controlling parameter for the predictions of shale gas and coalbed methane (CBM) productions. Shale matrix and tight anthracite are characterized by ultra-tight pore structure and low permeability at micro- and nano-scale with gas molecules stored by adsorption. Gas transport in shale and anthracite matrices no longer always falls into the continuum flow regime described by Darcys law, rather a considerable portion of transport is sporadic and irregular due to the mean free path of gas is comparable to the prevailing pore scale. Therefore, gas transport in both anthracite and shale will be a complicated nonlinear multi-mechanistic process. A multi-mechanistic flow process is always happening during shale gas and CBM production, including Darcy viscous flow, slip flow, transition flow and Knudsen diffusion and their proportional contributions to apparent permeability are constantly changing with continuous reservoir depletion. The complexity of the gas storage and flow mechanisms in ultra-fine pore structure is diverse and makes it more difficult to predict the matrix permeability and gas deliverability. In this study, a multi-mechanistic apparent-permeability model for unconventional reservoir rocks (shale and anthracite) was derived under different stress boundary conditions (constant-stress and uniaxial-strain). The proposed model incorporates the pressure-dependent weighting coefficients to separate the contributions of Knudsen diffusion and Darcy flow on matrix permeability. A combination of both permeability components was coupled with pressure-dependent weighting coefficients. A stressstrain relationships for a linear elastic gas-desorbing porous medium under hydrostatic stress condition was derived from thermal-elastic equations and can be incorporated into the Darcian flow component, serving for the permeability data under hydrostatic stress. The modeled results well agree with anthracite and shale sample permeability measured data.In this study, laboratory measurements of gas apparent permeability were conducted on coal and shale samples for both helium and CO2 injection/depletion under different stress conditions. At low pressure under constant stress condition, CO2 permeability enhancement due to sorption-induced matrix shrinkage effect is significant, which can be either clearly observed from the pulse-decay pressure response curves or the data reduced by Cui et al.s method. CO2 apparent permeability can be higher than He at pressure higher than 1000 psi, which may be resulted from limited shale adsorption capacity. Helium permeability is more sensitive to the variation of Terzaghi effective stress than CO2 and it is independent of pore pressure. The true effective stress coefficient can be found two values at low pressure region (500 psi) and high pressure region (500 psi). The negative value indicates Knudsen diffusion and slip flow effect have more impact on apparent permeability than Terzaghi stress at low pressure. Additionally, laboratory measurements of gas sorption, Knudsen diffusion coefficient and coal deformation were conducted to break down the key effects that influence gas permeability evolution. Adsorption isotherms of crushed anthracite coal samples was measured using Gibbs adsorption principle at different gas pressures. The adsorption isotherm result showed that the adsorption capacity at low pressure changes with a higher rate and thus brings a significant sorption-induced rock matrix swelling/shrinkage effect. And the isotherm data are important inputs for the Darcy permeability models. The latter was coupled in the apparent-permeability model as the Darcy flow component which involves the sorption-induced strain component. Diffusion coefficients of the pulverized samples were estimated by using the particle method and was used to calculate the effective Knudsen permeability. The Knudsen diffusion flow component in the proposed apparent-permeability model was constructed by transforming Knudsen mass flux into permeability term and used to match the effective Knudsen permeability based on diffusion data. Increasing trends for all results were performed during pressure drop down in the result plots. And the modeling result showed very good agreements with them, giving a solid proof of the availability of Knudsen diffusion component as part of the proposed model. The results of a series of experimental measurements of coal deformation with gas injection and depletion revealed that the coal sorption induced deformation exhibits anisotropy, with larger deformation in direction perpendicular to bedding than those parallel to the bedding planes. The deformation of coal is reversible for helium and methane with injection/depletion, but not for CO2. Based on the modeling results, it was found that application of isotropic deformation in permeability model can overestimate the permeability loss compared to anisotropic deformation. This demonstrates that the anisotropic coal deformation should be considered to predict the permeability behavior of CBM as well as CO2 sequestration/ECBM projects.

"Computational fluid dynamics (CFD) has been used to model 2-D well inflow over a range of permeabilities to study the impact of various well completion strategies (Augustine, 2011). Augustine's 2-D model was subsequently extended for 3-D flow by Thepporprapakorn (2013), for gas flow in the permeability range of tight gas (0.01 mD). This work presents a 3-D CFD model of gas inflow valid for extremely low ranges of permeability (0.00001 mD). In extremely low permeability, gas flow is complex and includes flow from fractures, flow through porous media, and diffusive gas transport. Diffusive gas transport is important when strong density and/or temperature gradients are present in the flow systems. The study introduces and applies the concept of three dimensions of extended Navier-Stokes equation (ENSE) to assess the impact of mass diffusive transport in low permeability rock. Two dimensions of ENSE were proposed previously by Rajamani (2013). Core samples from the Huai Hin Lat formation, Thailand, were analyzed for rock properties, geomechanical properties, and used in flow experiments to validate the modeling. CT scans were conducted on multiple planes of core samples, to identify fractures, which were included manually in the CFD modeling. Evaluations of the Huai Hin Lat shale indicate the shale has rock properties comparable to other commercial shales in the United States. Results of the CFD modeling demonstrate a relatively small impact (1%) of including three dimensional ENSE gas flow from extremely low permeability shale. The work provides an assessment of the importance of the diffusive flow contributions, in the range of extremely low permeability. Results of this work are used to inform development of a single 3-D CFD gas flow model that can be used in a parametric study of completion options, over a wide range of reservoir permeability"--Abstract, page iii.

Compared with conventional natural gas resources, shale gas reservoir, as a typical unconventional natural gas resource, has the characteristics of low porosity and low permeability. Therefore, the fractured horizontal well technology has been widely used in shale gas reservoir development. At the same time, more and more attention has been paid to the study of seepage mechanism. At present, conventional research on the seepage theory of fracturing horizontal wells in shale gas reservoirs are not very systematic, and the comprehensive consideration of adsorption, desorption and diffusion in the seepage model, especially in the linear flow model, is rarely given. Comprehensive consideration of adsorption, desorption and diffusion, using computer programming knowledge, such as shale gas reservoir fracturing horizontal well trilinear flow and five linear flow model, to research the shale gas reservoir fracturing horizontal well pressure dynamic features, provide theoretical basis for the development of shale gas. This paper mainly completes the following work: (1) Conduct in-depth research and analysis of a large number of literatures, analyze the characteristics of shale gas reservoir, and summarize its production and migration mechanism. (2) The continuity differential equation of each zone of the conventional trilinear flow and five linear flow model is derived, which provides the basic theoretical basis for the establishment of the trilinear flow and five linear flow model of shale gas reservoir. (3) Trilinear flow models and five linear flow models were established for fracturing horizontal Wells in single-medium shale gas reservoirs, and corresponding ii pressure characteristic curves were drawn to divide the flow stages. The influence of parameters such as adsorption and desorption coefficient, apparent permeability coefficient, fracture and reservoir conductivity, fracture spacing and pressure conductivity coefficient on the characteristic curve was analyzed. Trilinear flow model and five linear flow model are compared. (4) Trilinear flow models and five linear flow models are established for fracturing horizontal Wells in shale gas reservoirs with dual media. The models include: fracture seepage-matrix pseudo diffusion model, fracture seepage-matrix unsteady diffusion model. The corresponding pressure characteristic curve is drawn and the flow stage is divided. The effects of parameters such as elastic storage capacity ratio, interfacial flow coefficient, adsorption-desorption coefficient, fracture spacing and reservoir boundary length on the characteristic curve were analyzed. Trilinear flow model and five linear flow model are compared. (5) The application of the established model in well test interpretation and analysis of the measured data verifies the practicability of the theoretical model in this paper.

The current state of shale gas reservoir dynamics demands understanding long-term production, and existing models that address important parameters like fracture half-length, permeability, and stimulated shale volume assume constant permeability. Petroleum geologists suggest that observed steep declining rates may involve pressure-dependent permeability (PDP). This study accounts for PDP in three potential shale media: the shale matrix, the existing natural fractures, and the created hydraulic fractures. Sensitivity studies comparing expected long-term rate and pressure production behavior with and without PDP show that these two are distinct when presented as a sequence of coupled build-up rate-normalized pressure (BU-RNP) and its logarithmic derivative, making PDP a recognizable trend. Pressure and rate field data demonstrate evidence of PDP only in Horn River and Haynesville but not in Fayetteville shale. While the presence of PDP did not seem to impact the long term recovery forecast, it is possible to determine whether the observed behavior relates to change in hydraulic fracture conductivity or to change in fracture network permeability. As well, it provides insight on whether apparent fracture networks relate to an existing natural fracture network in the shale or to a fracture network induced during hydraulic fracturing. The electronic version of this dissertation is accessible from http://hdl.handle.net/1969.1/148240

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.

This book addresses the problems involved in the modelling and simulation of shale gas reservoirs, and details recent advances in the field. It discusses various modelling and simulation challenges, such as the complexity of fracture networks, adsorption phenomena, non-Darcy flow, and natural fracture networks, presenting the latest findings in these areas. It also discusses the difficulties of developing shale gas models, and compares analytical modelling and numerical simulations of shale gas reservoirs with those of conventional reservoirs. Offering a comprehensive review of the state-of-the-art in developing shale gas models and simulators in the upstream oil industry, it allows readers to gain a better understanding of these reservoirs and encourages more systematic research on efficient exploitation of shale gas plays. It is a valuable resource for researchers interested in the modelling of unconventional reservoirs and graduate students studying reservoir engineering. It is also of interest to practising reservoir and production engineers.