Shale gas accounts for an increasing proportion in the world,Äôs oil and gas supply, with the properties of low carbon, clean production, and huge potential for the compensation for the gradually depleted conventional resources. Due to the ubiquitous nanopores in shale matrix, the nanoscale gas flow becomes one of the most vital themes that are directly related to the formulation of shale gas development schemes, including the optimization of hydraulic fracturing, horizontal well spacing, etc. With regard to the gas flow in shale matrix, no commonly accepted consensus has been reached about the flow mechanisms to be considered, the coupled flow model in nanopores, and the upscaling method for its macroscopic form. In this chapter, the propositions of wall-associated diffusion, a physically sound flow mechanism scheme, a new coupled flow model in nanopores, the upscaling form of the proposed model, and the translation of lab-scale results into field-scale ones aim to solve the aforementioned issues. It is expected that this work will contribute to a deeper understanding of the intrinsic relationship among various flow mechanisms and the extension of the flow model to full flow regimes and to upscaling shale matrix, thus establishing a unified model for better guiding shale gas development.

Emerging Technologies in Hydraulic Fracturing and Gas Flow Modelling features the latest strategies for exploiting depleted and unconventional petroleum rock formations as well as simulating associated gas flow mechanisms. The book covers a broad range of multivarious stimulation methods currently applied in practice. It introduces new stimulation techniques including a comprehensive description of interactions between formation/hydraulic fracturing fluids and the host rock material. It provides further insight into practices aimed at advancing the operation of hydrocarbon reservoirs and can be used either as a standalone resource or in combination with other related literature. The book can serve as a propaedeutic resource and is appropriate for those seeking rudimentary information on the exploitation of ultra-impermeable oil and gas reservoirs. Professionals and researchers in the field of petroleum, civil, oil and gas, geotechnical and geological engineering who are interested in the production of unconventional petroleum resources as well as students undertaking studies in similar subject areas will find this to be an instructional reference.

The state of the art of modeling fluid flow in shale gas reservoirs is dominated by dual porosity models that divide the reservoirs into matrix blocks that significantly contribute to fluid storage and fracture networks which principally control flow capacity. However, recent extensive microscopic studies reveal that there exist massive micro- and nano- pore systems in shale matrices. Because of this, the actual flow mechanisms in shale reservoirs are considerably more complex than can be simulated by the conventional dual porosity models and Darcy's Law. Therefore, a model capturing multiple pore scales and flow can provide a better understanding of complex flow mechanisms occurring in these reservoirs. Through the use of a unique simulator, this research work establishes a micro-scale multiple-porosity model for fluid flow in shale reservoirs by capturing the dynamics occurring in three separate porosity systems: organic matter (mainly kerogen); inorganic matter; and natural fractures. Inorganic and organic portions of shale matrix are treated as sub-blocks with different attributes, such as wettability and pore structures. In the organic matter or kerogen, gas desorption and diffusion are the dominant physics. Since the flow regimes are sensitive to pore size, the effects of smaller pores (mainly nanopores and picopores) and larger pores (mainly micropores and nanopores) in kerogen are incorporated in the simulator. The separate inorganic sub-blocks mainly contribute to the ability to better model dynamic water behavior. The multiple porosity model is built upon a unique tool for simulating general multiple porosity systems in which several porosity systems may be tied to each other through arbitrary transfer functions and connectivities. This new model will allow us to better understand complex flow mechanisms and in turn to extend simulation to the reservoir scale including hydraulic fractures through upscaling techniques. The electronic version of this dissertation is accessible from http://hdl.handle.net/1969.1/151163

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.

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.

Shale gas development has more than 3 decades of history and remains one of the hottest topics in the petroleum industry. Shale gas development in China is underway. Our study focuses on an emerging marine shale gas reservoir in southern China, with its huge reserves that have attracted strong attention. The first part of this dissertation is the petrophysical characterization, which is an important step for a new shale gas play to better understand the geology of the formation, and it provides vital data to optimize a production plan and stimulation design. A systematic petrophysical study was conducted for the marine shale gas reservoir by conducting a series of 6 parallel experiments for 12 groups of samples to measure the total organic content (TOC), vitrinite reflectance (Ro), porosity, permeability, mineralogy, and gas content. Second, the extra-low porosity and permeability of shale formations complicate the mechanisms of shale gas storage and flow. Understanding the microstructure is significant for evaluating a new shale gas play toward accurate reserve estimation and recovery prediction. Both physical measurement (nitrogen adsorption experiment) and visualization technology (Scanning Electron Microscope) were used to characterize the nanopore structure of the Longmaxi Shale. Isotherms were obtained from adsorption experiments, and specific surface area and pore size distribution were calculated from the experimental results. Combining with the TOC, gas content, and mineralogy of the Longmaxi Shale, the significance and the controlling factors of the specific surface area and the nanopore volume were discussed. In addition, various types of porosity and several microfractures were observed from SEM images. Third, preliminary interpretation of the imaging logs revealed natural fractures in the formation that can significantly affect the production performance of shale gas wells since preexisting natural fractures will influence hydraulic fracture propagation. Thus, numerical simulation was conducted focusing on the interaction between hydraulically induced fractures and preexisting natural fractures. A hydraulic fracturing model considering the in-situ stress response to turbulent flow process was developed and validated with regression tests of a bi-wing hydraulic fracture model. Field-scale simulation results indicate that our model is capable of capturing the interactions between hydraulic fractures and the preexisting natural fractures defined by the initial fracture maps. Finally, a new model was built to model the actual network of hydraulic and preexisting fractures from geological interpretations and microseismic mapping results. The discrete fracture modeling (DFM) approach was applied to represent each fracture individually and explicitly. The near-well effects were modeled in detail by refining the unstructured 3D grid to the point where we fully resolve stimulated fractures. Simulations of the detailed model of an actual shale gas reservoir considered various mechanisms including adsorption/desorption, matrix/fracture transfer, and non-Darcy effects. Furthermore, the dissertation illustrates upscaling from the discrete fracture model to a coarse continuum model using multiple subregion (MSR), and the high degree of accuracy provided by this technique is demonstrated by comparing the solution of the upscaled model with the corresponding fine-grid solution for a synthetic case.