› › The Implications And Flow Behavior Of The Hydraulically Fractured Wells In Shale Gas Formation

The Implications and Flow Behavior of the Hydraulically Fractured Wells in Shale Gas Formation

Author : Anas Mohammadali S. Almarzooq

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Page : pages

File Size : 13,2 MB

Release : 2012

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Shale gas formations are known to have low permeability. This low permeability can be as low as 100 nano darcies. Without stimulating wells drilled in the shale gas formations, it is hard to produce them at an economic rate. One of the stimulating approaches is by drilling horizontal wells and hydraulically fracturing the formation. Once the formation is fractured, different flow patterns will occur. The dominant flow regime observed in the shale gas formation is the linear flow or the transient drainage from the formation matrix toward the hydraulic fracture. This flow could extend up to years of production and it can be identified by half slop on the log-log plot of the gas rate against time. It could be utilized to evaluate the hydraulic fracture surface area and eventually evaluate the effectiveness of the completion job. Different models from the literature can be used to evaluate the completion job. One of the models used in this work assumes a rectangular reservoir with a slab shaped matrix between each two hydraulic fractures. From this model, there are at least five flow regions and the two regions discussed are the Region 2 in which bilinear flow occurs as a result of simultaneous drainage form the matrix and hydraulic fracture. The other is Region 4 which results from transient matrix drainage which could extend up to many years. The Barnett shale production data will be utilized throughout this work to show sample of the calculations. This first part of this work will evaluate the field data used in this study following a systematic procedure explained in Chapter III. This part reviews the historical production, reservoir and fluid data and well completion records available for the wells being analyzed. It will also check for data correlations from the data available and explain abnormal flow behaviors that might occur utilizing the field production data. It will explain why some wells might not fit into each model. This will be followed by a preliminary diagnosis, in which flow regimes will be identified, unclear data will be filtered, and interference and liquid loading data will be pointed. After completing the data evaluation, this work will evaluate and compare the different methods available in the literature in order to decide which method will best fit to analyze the production data from the Barnett shale. Formation properties and the original gas in place will be evaluated and compared for different methods.



Simulating the Effect of Water on the Fracture System of Shale Gas Wells

Author : Hassan Hasan H. Hamam

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Page : pages

File Size : 25,14 MB

Release : 2011

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It was observed that many hydraulically fractured horizontal shale gas wells exhibit transient linear flow behavior. A half-slope on a type curve represents this transient linear flow behavior. Shale gas wells show a significant skin effect which is uncommon in tight gas wells and masks early time linear behavior. Usually 70-85 percent of frac water is lost in the formation after the hydraulic fracturing job. In this research, a shale gas well was studied and simulated post hydraulic fracturing was modeled to relate the effect of frac water to the early significant skin effect observed in shale gas wells. The hydraulically fractured horizontal shale gas well was described in this work by a linear dual porosity model. The reservoir in this study consisted of a bounded rectangular reservoir with slab matrix blocks draining into neighboring hydraulic fractures and then the hydraulic fractures feed into the horizontal well that fully penetrates the entire rectangular reservoir. Numerical and analytical solutions were acquired before building a 3D 19x19x10 simulation model to verify accuracy. Many tests were conducted on the 3D model to match field water production since initial gas production was matching the analytical solutions before building the 3D simulation model. While some of the scenarios tested were artificial, they were conducted in order to reach a better conceptual understanding of the field. Increasing the water saturation in the formation resulted in increasing water production while lowering gas production. Adding a fractured bottom water layer that leaked into the hydraulic fracture allowed the model to have a good match of water and gas production rates. Modeling trapped frac water around the fracture produced approximately the same amount of water produced by field data, but the gas production was lower. Totally surrounding the fracture with frac water blocked all gas production until some of the water was produced and gas was able to pass through. Finally, trapped frac water around the fracture as combined with bottom water showed the best results match. It was shown that frac water could invade the formation surrounding the hydraulic fracture and could cause formation damage by blocking gas flow. It was also demonstrated that frac water could partially block off gas flow from the reservoir to the wellbore and thus lower the efficiency of the hydraulic fracturing job. It was also demonstrated that frac water affects the square root of time plot. It was proven by simulation that the huge skin at early time could be caused by frac water that invades and gets trapped near the hydraulic fractures due to capillary pressure.



Study of Flow Regimes in Multiply-fractured Horizontal Wells in Tight Gas and Shale Gas Reservoir Systems

Author : Craig Matthew Freeman

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Page : pages

File Size : 26,74 MB

Release : 2010

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Various analytical, semi-analytical, and empirical models have been proposed to characterize rate and pressure behavior as a function of time in tight/shale gas systems featuring a horizontal well with multiple hydraulic fractures. Despite a small number of analytical models and published numerical studies there is currently little consensus regarding the large-scale flow behavior over time in such systems. The purpose of this work is to construct a fit-for-purpose numerical simulator which will account for a variety of production features pertinent to these systems, and to use this model to study the effects of various parameters on flow behavior. Specific features examined in this work include hydraulically fractured horizontal wells, multiple porosity and permeability fields, desorption, and micro-scale flow effects. The theoretical basis of the model is described in Chapter I, along with a validation of the model. We employ the numerical simulator to examine various tight gas and shale gas systems and to illustrate and define the various flow regimes which progressively occur over time. We visualize the flow regimes using both specialized plots of rate and pressure functions, as well as high-resolution maps of pressure distributions. The results of this study are described in Chapter II. We use pressure maps to illustrate the initial linear flow into the hydraulic fractures in a tight gas system, transitioning to compound formation linear flow, and then into elliptical flow. We show that flow behavior is dominated by the fracture configuration due to the extremely low permeability of shale. We also explore the possible effect of microscale flow effects on gas effective permeability and subsequent gas species fractionation. We examine the interaction of sorptive diffusion and Knudsen diffusion. We show that microscale porous media can result in a compositional shift in produced gas concentration without the presence of adsorbed gas. The development and implementation of the micro-flow model is documented in Chapter III. This work expands our understanding of flow behavior in tight gas and shale gas systems, where such an understanding may ultimately be used to estimate reservoir properties and reserves in these types of reservoirs.



Evidence of Reopened Microfractures in Production Data of Hydraulically Fractured Shale Gas Wells

Author : Sippakorn Apiwathanasorn

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Page : pages

File Size : 17,58 MB

Release : 2012

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Frequently a discrepancy is found between the stimulated shale volume (SSV) estimated from production data and the SSV expected from injected water and proppant volume. One possible explanation is the presence of a fracture network, often termed fracture complexity, that may have been opened or reopened during the hydraulic fracturing operation. The main objective of this work is to investigate the role of fracture complexity in resolving the apparent SSV discrepancy and to illustrate whether the presence of reopened natural fracture network can be observed in pressure and production data of shale gas wells producing from two shale formations with different well and reservoir properties. Homogeneous, dual porosity and triple porosity models are investigated. Sensitivity runs based on typical parameters of the Barnett and the Horn River shale are performed. Then the field data from the two shales are matched. Homogeneous models for the two shale formations indicate effective infinite conductivity fractures in the Barnett well and only moderate conductivity fractures in the Horn River shale. Dual porosity models can support effectively infinite conductivity fractures in both shale formations. Dual porosity models indicate that the behavior of the Barnett and Horn River shale formations are different. Even though both shales exhibit apparent bilinear flow behavior the flow behaviors during this trend are different. Evidence of this difference comes from comparing the storativity ratio observed in each case to the storativity ratio estimated from injected fluid volumes during hydraulic fracturing. In the Barnett shale case similar storativity ratios suggest fracture complexity can account for the dual porosity behavior. In the Horn River case, the model based storativity ratio is too large to represent only fluids from hydraulic fracturing and suggests presence of existing shale formation microfractures.



Long-term Well Performance Prediction in Unconventionaltight Gas And Shale Gas Reservoirs

Author : Pichit Vardcharragosad

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Page : pages

File Size : 20,90 MB

Release : 2014

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Unconventional tight gas and shale gas are the largest and fastest growing natural gas supply in the US. Natural gas produced from tight gas and shale gas reservoirs accounts for 60% of U.S. natural gas production in 2011. This number is expected to increase to 73% in 2040 (EIA, 2013). The lack of understanding and the lack of tools that can be applied to these unconventional plays are the major challenges. In unconventional tight gas and shale gas, the conventional reservoir engineering tools have been proven to be unsuccessful because they fail to capture the large differences in physical properties which heavily impact the production behaviors. The main differences include the ultra-low permeability of the formation, presence of adsorbed phase, and the need for multi-stage hydraulically fractured horizontal well completion to create massive flow area.This study aims to develop new reservoir engineering analysis techniques which fully apply for unconventional tight gas and shale gas reservoirs. The new techniques should be able to capture the reservoir responses that are characterized by the transient flow regime and the multi-mechanistic flow in ultra-low permeability formations, the complex flow pattern from hydraulic fracture completion, and the natural gas desorption. We focus on formulating the fundamental, physics-based governing equation for these tight gas and shale gas reservoirs, as well as the long-term analysis and prediction tools that can capture their physical properties. The research applies new promising tools, a density approach, which was proposed to the industry by our research group. In the density method, gas diffusivity equation will be solved in a density-based form, and effects of reservoir depletion on fluid properties are captured through dimensionless variable, [lambda]-[beta]. The density method has been proven to be a reliable production data analysis tool applicable to conventional gas reservoirs produced under constant flowing pressure, constant flow rate, variable pressure/rate constraint as well as in reservoirs with significant rock compressibility. In this thesis, we prove that density-based technique can be further extended to analyze production data from i) gas linear and fractal flow under boundary dominating condition, ii) gas radial, linear, and fractal flow with significant transient flow period, and iii) gas flow under slippage and desorption effects. We demonstrate that [lambda]-[beta] can effectively quantify effects of depletion on gas properties in reservoirs with linear, radial, and fractal flow. We also show how to incorporate slippage and desorption effects as well as transient flow effect by properly modified definitions of [lambda]-[beta]. Based on these results, we are able to show that the density-based production analysis tools, originally developed for conventional gas reservoirs under boundary dominated radial flow, can be applied to predict and analyze production from unconventional gas reservoirs. In addition, we are able to use these density-based tools to analyze the impact of flow geometries on production decline behavior of gas wells.



Geomechanics and Hydraulic Fracturing for Shale Reservoirs

Author : Yu Wang

Publisher : Scientific Research Publishing, Inc. USA

Page : 383 pages

File Size : 13,20 MB

Release : 2020-07-01

Category : Art

ISBN : 1618968963

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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.



A Comprehensive Numerical Model for Simulating Two-phase Flow in Shale Gas Reservoirs with Complex Hydraulic and Natural Fractures

Author : Mohammad Hamad AlTwaijri

Publisher :

Page : 158 pages

File Size : 12,4 MB

Release : 2017

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Increase in energy demand has played a significant role in the persistent exploitation and exploration of unconventional oil and gas resources. Shale gas reservoirs are one of the major unconventional resources. Advancements in horizontal drilling and hydraulic fracturing techniques have been the key to achieve economic rates of production from these shale gas reservoirs. In addition to their ultra-low permeability, shale gas reservoirs are characterized by their complex gas transport mechanisms and complex natural and induced (hydraulic) fracture geometries. Production from shale gas reservoirs is predominantly composed of two-phase flow of gas and water. However, proper modeling of the two-phase behavior as well as incorporating the complex fracture geometries have been a challenge within the industry. Due to the limitation of the local grid refinement (LGR) approach, hydraulic fractures are assumed to be planar (orthogonal), which is an unrealistic assumption. Although more flexible approaches are available, such as the use of unstructured grids, they require significantly high computational powers. In this research, an efficient embedded discrete fracture model (EDFM) is introduced to explicitly model complex fracture geometries. The EDFM approach is capable of explicitly modeling complex fracture geometries without increasing the computational demand. Utilizing EDFM alongside a commercial simulator, a 3D reservoir model is constructed to investigate the effect of complex fracture geometries on the two-phase flow of a shale gas well. In this investigation, varying degrees of hydraulic fracture complexity with 1-set and 2-set natural fractures were tested. The simulation results confirm the importance of properly modeling fracture complexity, highlighting that it plays an integral part in the estimation of gas and water recoveries. In addition, the simulation results hint to the pronounced effect of fracture interference as fracture complexity increases. Finally, variable fracture conductivities and initial water saturation values were analyzed to further assess their effect on the two-phase production behavior of the shale gas well. This study examines the effect of non-orthogonal complex fracture geometry on the two-phase flow of shale gas wells. The work can provide a significant insight toward understanding the extent to which fracture complexity can affect the performance of shale gas wells.





Hydraulic Fracturing in Unconventional Reservoirs

Author : Hoss Belyadi

Publisher : Gulf Professional Publishing

Page : 636 pages

File Size : 27,79 MB

Release : 2019-06-18

Category : Technology & Engineering

ISBN : 0128176660

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Book Description

Hydraulic Fracturing in Unconventional Reservoirs: Theories, Operations, and Economic Analysis, Second Edition, presents the latest operations and applications in all facets of fracturing. Enhanced to include today's newest technologies, such as machine learning and the monitoring of field performance using pressure and rate transient analysis, this reference gives engineers the full spectrum of information needed to run unconventional field developments. Covering key aspects, including fracture clean-up, expanded material on refracturing, and a discussion on economic analysis in unconventional reservoirs, this book keeps today's petroleum engineers updated on the critical aspects of unconventional activity. - Helps readers understand drilling and production technology and operations in shale gas through real-field examples - Covers various topics on fractured wells and the exploitation of unconventional hydrocarbons in one complete reference - Presents the latest operations and applications in all facets of fracturing



Impact of Slickwater Fracturing Fluid Compositions on the Petrophysical Properties of Shale and Tightsand

Author : Yongpeng Sun

Publisher :

Page : 180 pages

File Size : 31,67 MB

Release : 2014

Category : Enhanced oil recovery

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"A tight reservoir always requires hydraulic fracturing before production to increase production rate. The additives in hydraulic fluids are highly considerable for a successful stimulation. A friction reducer is often used to reduce the flowing friction in the wellbore during hydraulic fracturing. Extensive researches have been conducted to examine the extent it can reduce the fluid friction in tubings; however, no research has been reported on its behavior in a reservoir, which is related to the fracture extension. A breaker is also pumped into the formation to degrade the friction reducer. However, it is not clear that what is the best time to break it. After the hydraulic fracturing, the existence of liquid in matrix reduces the gas phase permeability. A surfactant is added to reduce water block by providing a low surface tension. However, the effect of the surfactant on the petrophysical properties of tight rocks is not clear. In this dissertation, the following four researches have been carried out, and significant findings have been summarized in conclusions. The friction reducer flow behavior in microfractures was studied firstly, including size effect, concentration effect, wettability effect, and etc. Consequently, various additives impact on the petrophysical properties on tight sand was examined, such as surface contact angle, gas phase permeability, liquid imbibition, and gas transportation. Then, formation damage of FR and breaker in tight sand was systematically investigated. The impact factors were disclosed in detail, including fluid concentration, sample length, breaking time, and permeability regain. Finally, surfactant wettability impact on liquid intake in shale was carried out carefully. The liquid intake rate affected by the existence of fractures, fluid concentration, sample length, and treatment method were specified in detail"--Abstract, page iii.