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Author: Reza Keshavarzi Publisher: ISBN: Category : Geotechnical engineering Languages : en Pages : 0
Book Description
During hydraulic fracturing in unconventional tight formations a high percentage of the injected fluid may remain in the formation and only a small portion of the fracturing fluid is typically recovered. Although spontaneous imbibition is mainly introduced as the main dominating mechanism, a clear understanding of the fundamental mechanisms through which the fracturing fluid would interact with the formation remains a challenge. The impact of these mechanisms on rock property changes is even more challenging but is important to account for post-fracturing reservoir characterization. In this study, an integrated analytical-experimental-numerical approach was adopted to study these issues using a case study within the Montney Formation in Farrell Creek field in northeast British Columbia. The results of experiments on Montney samples from different depths revealed that because of spontaneous water imbibition, the geomechanical properties of the samples were altered. Also, small scale heterogeneity in tight gas formations and shale results in these property changes occurring at various scales, such as beds. Property changes occurring along the beds and bedding planes, as a result of interaction with hydraulic fracturing fluid, can contribute to increased potential for shear failure along these planes. Therefore, a systematic micro-scale analysis (including micro-indentation and micro-scratch along the beds to capture micro-geomechanical responses) and macro-scale analysis (including ultrasonic measurements, uniaxial compressive loading in high and low capillary suctions and unloading-reloading cycles at varying capillary suction) have been developed and applied to capture the changes in rock behavior in different scales as a result of spontaneous water imbibition and how different behaviors in micro-scale would affect the responses in macro-scale. QEMSCAN analysis, nitrogen adsorption-desorption tests, thermogravimetric analysis (TGA), capillary condensation experiments, pressure-decay and pulse-decay permeability measurements and direct shear tests were also completed for quantitative analysis of minerals, pore shapes and porosity, initial water saturation, capillary suction as a function of water saturation, permeability and strength parameters in both macro-scale and micro-scale (bed-scale). QEMSCAN analysis indicated that mineral components were not the same in different beds and they could be categorized into quartz-rich and clay-rich. The results of the experimental phase indicated that the geomechanical and flow properties of Montney specimens were altered due to fluid imbibition. As the water saturation and capillary suction were changing in quartz-rich and clay-rich beds, they responded differently which would trigger some geomechanical behaviors in macro scale. In addition, it was observed that capillary suction would add extra stiffness and strength to the media and as it was diminishing, the media became weaker. A nonlinear response with hysteresis during unloading-reloading cycles at varying capillary suction implied that as a result of the water softening effect, the reduction in capillary suction and changing the local effective stress there is a high possibility of activation and propagation of pre-existing micro fractures. In the numerical modeling phase of this research, fully coupled poro-elastoplastic partially saturated models were developed that included transversely isotropic matrix properties and bed-scale geometry. Inclusion of bed-scale features in the numerical approach provided better analysis options since different properties of the adjacent beds (including different capillary suction change) that can trigger the failure in the planes of weakness (such as the interface between the beds) can be directly included in the model while it is not possible to have that in transversely isotropic numerical modeling. This implies that conventional numerical analysis of geomechanical responses originated from spontaneous imbibition needs to be revisited. Beds-included numerical analyses indicated that since the changes in local effective stress and rock mechanical properties were not the same in adjacent quartz-rich and clay-rich beds, differential volumetric strain along the interfaces between quartz-rich and clay-rich beds would take place which in turn generated induced shear stress components on the interface planes. For the interfaces where total shear stress along them exceeded the shear strength, failure occurred. Comparing the result of micro-geomechanical (bed scale) and macro-geomechanical analysis with the results of numerical modeling at reservoir in-situ conditions would suggest that as a result of post-fracturing spontaneous water imbibition in the studied Montney Formation, the failures/micro fractures would be generated along the interfaces. Then because of the propagation of activated pre-existing micro fractures in the adjacent beds followed by coalescence with the failed interfaces, a complex micro fracture network can be formed. Accordingly, rock mass geomechanical responses and flow properties would be affected which means that any numerical modeling or analytical approach to account for the production, refracturing and any other reservoir-related analysis without considering this fact is under question mark.
Author: Reza Keshavarzi Publisher: ISBN: Category : Geotechnical engineering Languages : en Pages : 0
Book Description
During hydraulic fracturing in unconventional tight formations a high percentage of the injected fluid may remain in the formation and only a small portion of the fracturing fluid is typically recovered. Although spontaneous imbibition is mainly introduced as the main dominating mechanism, a clear understanding of the fundamental mechanisms through which the fracturing fluid would interact with the formation remains a challenge. The impact of these mechanisms on rock property changes is even more challenging but is important to account for post-fracturing reservoir characterization. In this study, an integrated analytical-experimental-numerical approach was adopted to study these issues using a case study within the Montney Formation in Farrell Creek field in northeast British Columbia. The results of experiments on Montney samples from different depths revealed that because of spontaneous water imbibition, the geomechanical properties of the samples were altered. Also, small scale heterogeneity in tight gas formations and shale results in these property changes occurring at various scales, such as beds. Property changes occurring along the beds and bedding planes, as a result of interaction with hydraulic fracturing fluid, can contribute to increased potential for shear failure along these planes. Therefore, a systematic micro-scale analysis (including micro-indentation and micro-scratch along the beds to capture micro-geomechanical responses) and macro-scale analysis (including ultrasonic measurements, uniaxial compressive loading in high and low capillary suctions and unloading-reloading cycles at varying capillary suction) have been developed and applied to capture the changes in rock behavior in different scales as a result of spontaneous water imbibition and how different behaviors in micro-scale would affect the responses in macro-scale. QEMSCAN analysis, nitrogen adsorption-desorption tests, thermogravimetric analysis (TGA), capillary condensation experiments, pressure-decay and pulse-decay permeability measurements and direct shear tests were also completed for quantitative analysis of minerals, pore shapes and porosity, initial water saturation, capillary suction as a function of water saturation, permeability and strength parameters in both macro-scale and micro-scale (bed-scale). QEMSCAN analysis indicated that mineral components were not the same in different beds and they could be categorized into quartz-rich and clay-rich. The results of the experimental phase indicated that the geomechanical and flow properties of Montney specimens were altered due to fluid imbibition. As the water saturation and capillary suction were changing in quartz-rich and clay-rich beds, they responded differently which would trigger some geomechanical behaviors in macro scale. In addition, it was observed that capillary suction would add extra stiffness and strength to the media and as it was diminishing, the media became weaker. A nonlinear response with hysteresis during unloading-reloading cycles at varying capillary suction implied that as a result of the water softening effect, the reduction in capillary suction and changing the local effective stress there is a high possibility of activation and propagation of pre-existing micro fractures. In the numerical modeling phase of this research, fully coupled poro-elastoplastic partially saturated models were developed that included transversely isotropic matrix properties and bed-scale geometry. Inclusion of bed-scale features in the numerical approach provided better analysis options since different properties of the adjacent beds (including different capillary suction change) that can trigger the failure in the planes of weakness (such as the interface between the beds) can be directly included in the model while it is not possible to have that in transversely isotropic numerical modeling. This implies that conventional numerical analysis of geomechanical responses originated from spontaneous imbibition needs to be revisited. Beds-included numerical analyses indicated that since the changes in local effective stress and rock mechanical properties were not the same in adjacent quartz-rich and clay-rich beds, differential volumetric strain along the interfaces between quartz-rich and clay-rich beds would take place which in turn generated induced shear stress components on the interface planes. For the interfaces where total shear stress along them exceeded the shear strength, failure occurred. Comparing the result of micro-geomechanical (bed scale) and macro-geomechanical analysis with the results of numerical modeling at reservoir in-situ conditions would suggest that as a result of post-fracturing spontaneous water imbibition in the studied Montney Formation, the failures/micro fractures would be generated along the interfaces. Then because of the propagation of activated pre-existing micro fractures in the adjacent beds followed by coalescence with the failed interfaces, a complex micro fracture network can be formed. Accordingly, rock mass geomechanical responses and flow properties would be affected which means that any numerical modeling or analytical approach to account for the production, refracturing and any other reservoir-related analysis without considering this fact is under question mark.
Author: Ekrem Alagoz Publisher: ISBN: Category : Languages : en Pages : 146
Book Description
In petroleum engineering, hydraulic fracturing has been developed to mitigate the crucial problem of the world's dwindling oil supplies. Thanks to hydraulic fracturing, engineers can create new artificial apertures with pressurized fluids. The process includes the high-pressure injection of a fracking fluid, which is basically water and proppants. Hydrocarbons will flow more freely after the flow back of water. Once the pumping of fracturing fluid is stopped, created fractures begin to close, as the stress increases. This has become a critical issue because closing these fractures results in a rapid decline in productivity of the well. The primary reason for proppant usage is to settle between fracture apertures and prop them open in order to increase oil and gas productivity. Proppant embedment is a crucial problem that causes many fractures to fail over time. Fractured well productivity can be dramatically reduced by severe proppant embedment due to a reduction in fracture aperture. Accordingly, understanding the proppant embedment phenomena is essential for hydraulic fracturing treatments. In this thesis, the mechanisms of proppant embedment have been investigated by quantifying the stress-dependent deformations (elastic and plastic) as well as the time-dependent deformation (creep). A set of constitutive equations were developed to account for elastic, plastic, and creep deformation during proppant embedment. Two new experimental apparatuses have been built and used to quantify the shale rock proppant deformation behavior (elastic, plastic, and creep) after exposure to various fracture fluid additives such as surfactants and clay stabilizers. Results show that proppant embedment primarily occurs due to plastic deformation followed by time-dependent creep deformation, while elastic deformation is small. The impact of different fracturing fluids and rock mineralogy on proppant embedment were also studied. Our results show that fluid chemistry substantially affects the amount of plastic deformation and creep. For example, KCI with a Clay Inhibitor was quite successful in reducing the proppant embedment. Shales with high clay-content embedded proppant at lower stresses and showed more plastic deformation. The test results show that 15% more clay-content shale samples experienced almost 50% more deformation. Chemical treatments fostered the best improvements or degradations in high clay-content shales
Author: Zhenning Yang Publisher: ISBN: Category : Languages : en Pages :
Book Description
Mitigation and prevention of shale-formation damage caused by hydraulic-fracturing fluid/rock interactions play an important role in well-production stability and subsequent refracturing design. This study presents three experimental investigations on the interaction of water/shale, fluid/clay, and fluid/shale. A series of experiments were designed to investigate fluid/shale interactions: hydrophilic to hydrophobic alteration through chemical-vapor deposition, nanoindentation testing on shale sample, geotechnical laboratory experiments on contaminated clay, X-ray photoelectron spectroscopy (XPS), X-ray diffraction (XRD), and scanning electron microscope (SEM) on shale sample. A clay-matrix-based data-screening criterion is proposed for nanoindentation. The continuous-stiffness-measurment (CSM) method is proved to have better definition and characterization of softening of shale based on the proposed criterion. This study furthered the numerical model of clay deformation by Hattab and Chang (2015) by considering different pore fluid concentration. The fracturing fluid contaminated clay produced changes of geotechnical properties. Based on the proposed criterion and designed experiments, fracturing fluid contaminated shale was observed to gain 4 to 6% of NaCl. However, all other minerals contents are found to decrease after the shale powder-fluid interaction. A characteristic depth was proposed to consider reduction of hardness and mineral content at the same time. Moreover, an empirical equation was proposed to describe fracture toughness of shale by using a selection of indentation depth, its corresponding hardness and Young's modulus.
Author: Yu Wang Publisher: Scientific Research Publishing, Inc. USA ISBN: 1618968963 Category : Art Languages : en Pages : 383
Book Description
This book is intended as a reference book for advanced graduate students and research engineers in shale gas development or rock mechanical engineering. Globally, there is widespread interest in exploiting shale gas resources to meet rising energy demands, maintain energy security and stability in supply and reduce dependence on higher carbon sources of energy, namely coal and oil. However, extracting shale gas is a resource intensive process and is dependent on the geological and geomechanical characteristics of the source rocks, making the development of certain formations uneconomic using current technologies. Therefore, evaluation of the physical and mechanical properties of shale, together with technological advancements, is critical in verifying the economic viability of such formation. Accurate geomechanical information about the rock and its variation through the shale is important since stresses along the wellbore can control fracture initiation and frac development. In addition, hydraulic fracturing has been widely employed to enhance the production of oil and gas from underground reservoirs. Hydraulic fracturing is a complex operation in which the fluid is pumped at a high pressure into a selected section of the wellbore. The interaction between the hydraulic fractures and natural fractures is the key to fracturing effectiveness prediction and high gas development. The development and growth of a hydraulic fracture through the natural fracture systems of shale is probably more complex than can be described here, but may be somewhat predictable if the fracture system and the development of stresses can be explained. As a result, comprehensive shale geomechanical experiments, physical modeling experiment and numerical investigations should be conducted to reveal the fracturing mechanical behaviors of shale.
Author: Kenneth Imo-Imo Israel Eshiet Publisher: ISBN: 1838811079 Category : Chemistry, Technical Languages : en Pages : 152
Book Description
The stimulation of unconventional hydrocarbon reservoirs is proven to improve their productivity to an extent that has rendered them economically viable. Generally, the stimulation design is a complex process dependent on intertwining factors such as the history of the formation, rock and reservoir fluid type, lithology and structural layout of the formation, cost, time, etc. A holistic grasp of these can be daunting, especially for people without sufficient experience and/or expertise in the exploitation of unconventional hydrocarbon reserves. This book presents the key facets integral to producing unconventional resources, and how the different components, if pieced together, can be used to create an integrated stimulation design. Areas covered are as follows: • stimulation methods, • fracturing fluids, • mixing and behavior of reservoir fluids, • assessment of reservoir performance, • integration of surface drilling data, • estimation of geomechanical properties and hydrocarbon saturation, and • health and safety. Exploitation of Unconventional Oil and Gas Resources: Hydraulic Fracturing and Other Recovery and Assessment Techniques is an excellent introduction to the subject area of unconventional oil and gas reservoirs, but it also complements existing information in the same discipline. It is an essential text for higher education students and professionals in academia, research, and the industry.
Author: Publisher: ISBN: Category : Languages : en Pages :
Book Description
Frac fluid flow, structure, and fracture mechanics simulations are developed for predicting and optimizing fracture dimensions and fluid leak-offs. Roles of in situ stress and material properties for possible vertical migration of fractures from the pay zone are discussed. Rationale for foam and dendritic fracturing experiments is presented along with numerical experiments for examining the phenomena of spalling of the fracture faces and conditions for secondary fracture initiation. Assignment of conventional, foam, cyrogenic, dendritic, and explosive fracturing treatments for specific reservoir properties is considered. Variables include fracture density and extent, shale thickness, in-situ stress gradients, energy assist mechanisms, well clean-up, shale-frac fluid interaction, proppant selection, and fracture height control. The analysis suggests that correlation with prevailing in situ stress gradients are promising diagnostic indicators for fracture treatment selection and design. In conclusion, the comprehensive development of an economical strategy requires extensive and controlled field testing with supporting predictive analyses of reservoir responses. Finite element modeling of reservoir in situ stress trajectories and the flow and fracture responses in the reservoir is recommended.
Author: Peidong Zhao Publisher: ISBN: Category : Languages : en Pages : 0
Book Description
Stimulated reservoir volume (SRV) is a prime factor controlling well performance in unconventional shale plays. In general, SRV describes the topology of induced fractures by hydraulic fracturing. Natural fractures (NFs), such as joints and faults, are ubiquitous in oil and gas reservoirs, where their tectonics, diagenesis, and hydrocarbon-generation history make the rock prone to fracturing. Being a pre-existing weak interface, NFs are preferred failure paths during hydraulic fracturing and becoming conductive under shear slip. Therefore, the interaction of hydraulic fractures (HFs) and NFs is fundamental to fracture growth in a formation. However, field observations of induced fracture systems show the necessity of modeling fracture complexity for improving completion design and interpreting drained reservoir volume (DRV). Thus, this work explains the mechanisms of HF-NF interaction and provides a physics-based method to infer SRV. First, fracture complexity results from fracture-tip processes involving stress perturbation by HF and failure of the pre-existing weak interface. Such so-called HF-NF interactions enable permeability enhancement around the HF and the development of SRV within unconventional shale reservoirs. This work proposes a two-dimensional (2D) analytical workflow to delineate the potential slip zone (PSZ) induced by an HF. An explicit description of failure modes in the near-tip region explains the complexity involved in HF-NF interaction. The results show varying influences of HF-NF relative angle, stress state, net pressure, frictional coefficient, and HF length to the NF slip. An NF at a 30±5° relative angle to an HF is analytically proved to have the highest potential for reactivation, which dominantly depends on the frictional coefficient of the interface. The spatial extension of the PSZ normal to the HF converges as the fracture propagates away and exhibits asymmetry depending on the relative angle. The proposed concept of PSZ can be used to measure and compare the intensity of HF-NF interactions at various geological settings. Second, the intensity of HF-NF interaction has been found to vary by formation and shale play. The problem of HF-NF interaction is multivariant and nonlinear, requiring conditional screening among three failure modes. By considering realistic subsurface conditions, a machine-learning (ML) model (random forest [RF] regression) is built to replicate the physics-based model and statistically investigate parametric influences on NF slip. The ML model finds the statistical significance of predicting features to be in the order of relative angle between HF and NF, fracture gradient (FG), frictional coefficient of the NF, overpressure index, stress differential, formation depth, and net pressure. The ML result is compared with sensitivity analysis and provides a new perspective on HF-NF interaction using statistical measures. The importance of formation depth on HF-NF interaction is stressed in both the physics-based and data-driven models, thus providing insight for field development of stacked resource plays. Finally, previous fracturing models either reduce model flexibility in simulating complex HF-NF interaction or require great computation cost for discrete fracture growth. This work presents a finite discrete-element model, which is a hybrid model adopting numerical setups from both continuum and discontinuous approaches, to investigate multifracture propagation in fractured reservoirs. The numerical model captures the fracture complexity, including branched, stranded, and kinked fractures, as well as the offset crossing of NFs. The results show biased fracture growth in the fractured reservoir, which is different from the numerical results of multifracture propagation in homogeneous rocks.. This work also emphasizes the control of fluid partition at the wellbore and among the intersecting fractures. Fluid partition at the wellbore is found to be a major challenge to the completion design of tight cluster spacing, which has been shown to improve production in recent years
Author: Johannes Fink Publisher: Gulf Professional Publishing ISBN: 0123838452 Category : Technology & Engineering Languages : en Pages : 809
Book Description
Petroleum Engineer's Guide to Oil Field Chemicals and Fluids is a comprehensive manual that provides end users with information about oil field chemicals, such as drilling muds, corrosion and scale inhibitors, gelling agents and bacterial control. This book is an extension and update of Oil Field Chemicals published in 2003, and it presents a compilation of materials from literature and patents, arranged according to applications and the way a typical job is practiced. The text is composed of 23 chapters that cover oil field chemicals arranged according to their use. Each chapter follows a uniform template, starting with a brief overview of the chemical followed by reviews, monomers, polymerization, and fabrication. The different aspects of application, including safety and environmental impacts, for each chemical are also discussed throughout the chapters. The text also includes handy indices for trade names, acronyms and chemicals. Petroleum, production, drilling, completion, and operations engineers and managers will find this book invaluable for project management and production. Non-experts and students in petroleum engineering will also find this reference useful. Chemicals are ordered by use including drilling muds, corrosion inhibitors, and bacteria control Includes cutting edge chemicals and polymers such as water soluble polymers and viscosity control Handy index of chemical substances as well as a general chemical index
Author: Caineng Zou Publisher: Elsevier ISBN: 0128122358 Category : Technology & Engineering Languages : en Pages : 508
Book Description
Unconventional Petroleum Geology, Second Edition presents the latest research results of global conventional and unconventional petroleum exploration and production. The first part covers the basics of unconventional petroleum geology, its introduction, concept of unconventional petroleum geology, unconventional oil and gas reservoirs, and the origin and distribution of unconventional oil and gas. The second part is focused on unconventional petroleum development technologies, including a series of technologies on resource assessment, lab analysis, geophysical interpretation, and drilling and completion. The third and final section features case studies of unconventional hydrocarbon resources, including tight oil and gas, shale oil and gas, coal bed methane, heavy oil, gas hydrates, and oil and gas in volcanic and metamorphic rocks. Provides an up-to-date, systematic, and comprehensive overview of all unconventional hydrocarbons Reorganizes and updates more than half of the first edition content, including four new chapters Includes a glossary on unconventional petroleum types, including tight-sandstone oil and gas, coal-bed gas, shale gas, oil and gas in fissure-cave-type carbonate rocks, in volcanic reservoirs, and in metamorphic rocks, heavy crude oil and natural bitumen, and gas hydrates Presents new theories, new methods, new technologies, and new management methods, helping to meet the demands of technology development and production requirements in unconventional plays
Author: Reza Keshavarzi
Author: Reza Keshavarzi
Author: Ekrem Alagoz
Author: Zhenning Yang
Author: Wenting Yue
Author: Yu Wang
Author: Kenneth Imo-Imo Israel Eshiet
Author: 
Author: Peidong Zhao
Author: Johannes Fink
Author: Caineng Zou