Experimental Studies on the Reservoir Dynamics of Water-based and Gas-based Fracturing Fluids in Tight Rocks PDF Download

Author: Xiao Luo
Publisher:
ISBN:
Category :
Languages : en
Pages : 0

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Book Description
Low permeability formations, including shale and tight reservoirs, have contributed over 50% of U.S. annual oil production. Many of these formations are oil productive formations, they include Bakken, Eagle Ford, Marcellus, Permian, and Utica. In order to obtain economic production, large amounts of fracturing fluids are consumed during the hydraulic fracturing treatments, but only a small fraction of the fluid is returned to the surface as flowback. Water-based fracturing fluids may invade the rock matrix in a tight or unconventional reservoir and result in a water block that hinders oil production. To remedy this possibility, gas- and foam-based fluids have been developed. For an oil productive formation, the invasion of gas can also result in oil permeability reduction, i.e. a gas block, but the mechanism and clean up are likely to be different than a water block. As the two fluids exhibit different wetting nature, it is not clear how they compare to each other in a multi-phase flow perspective, such as their impact on the productivity in the short and long term. In this work, we conduct experimental studies the reservoir dynamics of invaded fracturing fluids, reduction in the hydrocarbon permeability, and potential mitigation for cleaning up the fluid block. We scaled down this fluid invasion problem to a laboratory core sample. Water and N2 are injected into a rock matrix to mimic the invasion of slickwater and gas-based fracturing fluids, respectively. We studied the evolution of the oil productivity and flowback versus time during the oil production. The respective performances for different fracturing fluids under different conditions will also be investigated in this study.

Author: Amber E. Zandanel
Publisher:
ISBN: 9781392073452
Category : Hydraulic fracturing
Languages : en
Pages : 63

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Book Description
Hydraulic fracturing of unconventional reservoirs in the Powder River Basin in Wyoming and Montana is a growing source of oil and gas production. However, shale and tight-oil reservoirs in the region have high rates of decline in production compared to conventional oil and gas extraction, severely limiting well life. The full reasons for these high decline rates are unclear and have been attributed to a number of causes, including porosity decrease from fines migration. Recent field and experimental studies have shown that water-rock interaction with hydraulic fracturing fluid can cause mineral precipitation in the reservoir subsurface. Experimental studies into water-rock interaction also suggest that reservoirs are sensitive to changes in mineral surface area and to oil adhering to the mineral grains. This study tests the potential effect on water-rock interaction of removing residual oil from unconventional reservoir rock at reservoir conditions as found in the Powder River Basin in Wyoming. Rock samples from the Parkman Sandstone in the Powder River Basin, Wyoming were combined with synthesized formation water at in-situ reservoir conditions and reacted for ~35 days to approach steady-state. A simulated hydraulic fracturing fluid was then injected and reactions proceeded for another ~35 days. Fluid samples were collected throughout the experiment. One experiments uses rocks chemically processed to remove residual oil (low-residual oil, or LRO) and one uses rocks that retain residual oil (high-residual oil, or HRO). All experiments use 0.5–1 cm rock cubes to emulate the interface between fractures and the rock matrix. Analyzed chemistry results from aqueous samples collected during the experiments indicate water-rock interaction with both carbonates and clay minerals. Observation of rock recovered from the experiments shows changes to mineralogy visible in microscope or SEM. Fluid results suggest that unconventional reservoir rock with less residual oil at the mineral face is more prone to carbonate dissolution than reservoir rock with residual oil at the fracture face. Little evidence of precipitation or dissolution was observed on the recovered rock after experiments; however, water-rock interaction at the timescales of these experiments is not likely to cause significant changes to in-situ reservoir porosity or permeability. The water-silicate interaction trend suggests that the fluid chemistry may favor smectite or other clay precipitation at timescales beyond those represented in the experiments.

Author: Nick Bahrami
Publisher: Springer Science & Business Media
ISBN: 3319024817
Category : Technology & Engineering
Languages : en
Pages : 66

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Book Description
Tight gas reservoirs have very low permeability and porosity, which cannot be produced at economical flow rates unless the well is efficiently stimulated and completed using advanced and optimized technologies. Economical production on the basis of tight gas reservoirs is challenging in general, not only due to their very low permeability but also to several different forms of formation damage that can occur during drilling, completion, stimulation, and production operations. This study demonstrates in detail the effects of different well and reservoir static and dynamic parameters that influence damage mechanisms and well productivity in tight gas reservoirs. Geomechanics, petrophysics, production and reservoir engineering expertise for reservoir characterization is combined with a reservoir simulation approach and core analysis experiments to understand the optimum strategy for tight gas development, delivering improved well productivity and gas recovery.

Author: Juan Correa Castro
Publisher:
ISBN:
Category :
Languages : en
Pages :

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Book Description
Unconventional gas has become an important resource to help meet our future energy demands. Although plentiful, it is difficult to produce this resource, when locked in a massive sedimentary formation. Among all unconventional gas resources, tight gas sands represent a big fraction and are often characterized by very low porosity and permeability associated with their producing formations, resulting in extremely low production rate. The low flow properties and the recovery factors of these sands make necessary continuous efforts to reduce costs and improve efficiency in all aspects of drilling, completion and production techniques. Many of the recent improvements have been in well completions and hydraulic fracturing. Thus, the main goal of a hydraulic fracture is to create a long, highly conductive fracture to facilitate the gas flow from the reservoir to the wellbore to obtain commercial production rates. Fracture conductivity depends on several factors, such as like the damage created by the gel during the treatment and the gel clean-up after the treatment. This research is focused on predicting more accurately the fracture conductivity, the gel damage created in fractures, and the fracture cleanup after a hydraulic fracture treatment under certain pressure and temperature conditions. Parameters that alter fracture conductivity, such as polymer concentration, breaker concentration and gas flow rate, are also examined in this study. A series of experiments, using a procedure of "dynamical fracture conductivity test," were carried out. This procedure simulates the proppant/frac fluid slurries flow into the fractures in a low-permeability rock, as it occurs in the field, using different combinations of polymer and breaker concentrations under reservoirs conditions. The result of this study provides the basis to optimize the fracturing fluids and the polymer loading at different reservoir conditions, which may result in a clean and conductive fracture. Success in improving this process will help to decrease capital expenditures and increase the production in unconventional tight gas reservoirs.

Author: Reza Keshavarzi
Publisher:
ISBN:
Category : Geotechnical engineering
Languages : en
Pages : 0

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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: Tianbo Liang
Publisher:
ISBN:
Category :
Languages : en
Pages : 506

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Book Description
In the U.S., over half of the oil and gas production comes from hydraulically fractured wells in 2015; and the current trend is to inject more fracturing fluids (typically water) and proppants to create more complex fracture network and maximize the contact area with the formation. Hydrocarbon is mainly produced from the reservoir rock adjacent to the open fractures; therefore, any water left behind therein can block the flow of hydrocarbon and thus reduce the overall well productivity. In this study, it is proposed that matrix-fracture interaction is crucial to understanding the water block. Water can be retained in the matrix through this interaction, which is analogous to capillary end effect in laboratory measurements. This can be typically ignored in conventional reservoirs with long length scales and large pressure drawdown relative to capillary pressure. However, this should not be ignored in the fractured low permeability reservoirs where hydrocarbon production comes from short distances from the fractures and pressure drawdown is not significantly higher than capillary pressure. Additionally, water block in different wetting conditions needs to be studied so that mitigation methods can be wisely chosen to solve the right problem and enhance hydrocarbon production effectively and efficiently. This is experimentally achieved by using a three-step coreflood platform. This platform simulates the fracturing fluid invasion as well as the flowback occurring within the rock matrix adjacent to the fracture face. Under various mimicked reservoir/production conditions, regaining of rock permeability to hydrocarbon is obtained from measuring pressure drop versus time; this is further compared with the change of phase saturations in real-time either through flowback/effluent measurement or CT scans for the entire period of the coreflood. Based on the coreflood results, a more comprehensive understanding is achieved regarding the water block from fracturing in low permeability rocks. To mitigate water block, three major methods have been suggested based on field and/or laboratory studies. They are drawdown management, shut-in/soaking treatment, and surfactant or volatile additive treatment. Our experimental methods also provide a new avenue to compare the efficiency and effectiveness of various mitigation methods in different mimicked reservoir conditions, so that their governing mechanisms can be elucidated from the viewpoint of multiphase flow. For water-wet portion of the rock, matrix-fracture interaction dominates the early-time water block; the smaller the rock permeability, the longer its time-span. Once this interaction disappears, water block becomes the general form of capillary trapping. Shut-in/soaking is only effective on cleaning up the first form of water block and increasing the early-time production; however, it is unlikely to accelerate the spontaneous imbibition that mitigates such damage naturally, and shut-in does not increase the ultimate hydrocarbon production rate. Surfactant is very promising on cleaning up both forms of water block; among all tested formulations, the one generating Winsor type-I microemulsions with the mimicked reservoir oil shows the best performance. For oil-wet portion of the rock, water block is mainly in the general form of capillary trapping. Trapped water within pore bodies creates a more serious reduction on rock permeability to hydrocarbon comparing to the water-wet condition. To mitigate such water block, two typical surfactant treatments are mainly focused and compared, which are altering the rock wettability and achieving ultralow IFT with the reservoir oil. Synthesizing all the results, it is proposed that achieving ultralow IFT seems to be a better option for mitigating water block in oil-wet low permeability rocks.

Author: Qiquan Ran
Publisher: Springer Nature
ISBN: 9813298480
Category : Technology & Engineering
Languages : en
Pages : 411

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Book Description
This book systematically introduces readers to the simulation theory and techniques of multiple media for unconventional tight reservoirs. It summarizes the macro/microscopic heterogeneities; the features of multiscale multiple media; the characteristics of complex fluid properties; the occurrence state of continental tight oil and gas reservoirs in China; and the complex flow characteristics and coupled production mechanism under unconventional development patterns. It also discusses the simulation theory of multiple media for unconventional tight oil and gas reservoirs; mathematic model of flow through discontinuous multiple media; geological modeling of discrete multiscale multiple media; and the simulation of multiscale, multiphase flow regimes and multiple media. In addition to the practical application of simulation and software for unconventional tight oil and gas, it also explores the development trends and prospects of simulation technology. The book is of interest to scientific researchers and technicians engaged in the development of oil and gas reservoirs, and serves as a reference resource for advanced graduate students in fields related to petroleum.

Author: Lu Wang
Publisher: Springer Nature
ISBN: 981199708X
Category : Science
Languages : en
Pages : 335

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Book Description
This book provides a systematical investigation on the reservoir characteristics and percolation mechanism of ultradeep carbonate gas reservoirs, including reservoir characteristics and classification, gas storage and percolation capacities, gas-phase and gas-water two-phase percolation mechanism, microscale complex gas-water relationship, reservoir sensitivity characteristics, and gas production characteristics of heterogeneous carbonate reservoirs. Some advanced and improved experimental techniques and analytical methods are introduced and applied, including comprehensive evaluation technique of storage and percolation capacities, ultra-high temperature and pressure physical simulation experiment technique, microscopic visualization technique based on CT scanning and microelectronics lithography, and physical simulation technique for heterogeneous reservoir development. In addition, it summarizes strategies for the efficient development of ultradeep carbonate gas reservoirs based on these theoretical research results. The key techniques and methods introduced in this monograph satisfy the need for efficient development of ultradeep carbonate gas reservoirs and provide theoretical basis and methodological value for investigations on similar gas reservoirs. This book serves as a reference for engineering technical professionals, researchers, and graduate students who are engaged in the exploration and development of carbonate gas reservoirs.

Author:
Publisher:
ISBN:
Category : Power resources
Languages : en
Pages : 754

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Author: David Wood
Publisher: Gulf Professional Publishing
ISBN: 0323859569
Category : Science
Languages : en
Pages : 412

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Book Description
Sustainable Natural Gas Reservoir and Production Engineering, the latest release in The Fundamentals and Sustainable Advances in Natural Gas Science and Engineering series, delivers many of the scientific fundamentals needed in the natural gas industry, including improving gas recovery, simulation processes for fracturing methods, and methods for optimizing production strategies. Advanced research covered includes machine learning applications, gas fracturing mechanics aimed at reducing environmental impact, and enhanced oil recovery technologies aimed at capturing carbon dioxide. Supported by corporate and academic contributors along with two well-distinguished editors, this book provides today’s natural gas engineers the fundamentals and advances in a convenient resource Helps readers advance from basic equations used in conventional gas reservoirs Presents structured case studies to illustrate how new principles can be applied in practical situations Covers advanced topics, including machine learning applications to optimize predictions, controls and improve knowledge-based applications Helps accelerate emission reductions by teaching gas fracturing mechanics with an aim of reducing environmental impacts and developing enhanced oil recovery technologies that capture carbon dioxide