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Fracturing with Carbon Dioxide: From Microscopic Mechanism to Reservoir Application
Abstract
Water fracturing is widely employed as a reservoir-stimulating technology for the recovery of unconventional oil and gas. However, the process suffers from massive water consumption and environmental concerns. Therefore, alternative fracturing fluids are desired. In recent years, fracturing with CO2 was proposed to embracemultiple benefits, including carbon storage, enhanced recovery, etc. Herein, based on specially designed facilities and new analytical methodologies, we present multiscale and quantitative investigations on the fracturing mechanism and behavior of CO2 and water. It was demonstrated that because of the high leak-off of CO2, shear fractures can be readily induced, which facilitated the formation of tensile and mixed fractures, leading to effective fracturing, complex networks, and greater stimulated reservoir volume. Finally, a 4- to 20- fold increase in tight oil production could be achieved by CO2 fracturing in field tests with five wells.
... In recent years, liquid or supercritical CO 2 fracturing and displacement mining technology have achieved remarkable results in the field of unconventional oil and gas reservoirs [14,15,16] and have been extended to the fields of CBM development and mine gas control, mainly including fracturing coal rock [17,18,19] and gas displacement [20,21,22,23,24,25]. How to arrange the spacing (L) between CO 2 injection well and drainage well more reasonably and select the appropriate displacement pressure (P) is the key to Therefore, it is unreasonable to determine the key parameters for engineering applications using Darcy's law alone. ...
... The starting pressure gradient M is a constant value of the pressure gradient ΔP/L. When the outlet flow q is 0, the value of ΔP/L is M i , and Equation (13) can be transformed into Equation (14). ...
... Lowtemperature nitrogen adsorption and high-pressure mercury injection methods were combined to analyse the pore distribution characteristics in the full aperture range, as shown in Figure 12. In addition, in the process of solving, considering the critical pore diameter range corresponding to the percolation region of single-component CO 2 and CH 4 gases under different pressure conditions (as shown in Table 5) and substituting the interfacial action coefficient (ε) into Equation (14), the dynamic resistance corresponding to the pore diameter range under different pressure gradients was obtained. ...
China’s coal seam permeability is low, and the original coal seam gas extraction is difficult. CO2 displacement of coal seam CH4 technology is an effective gas extraction technology. CO2 is injected into the coal seam under pressure, and competitive adsorption occurs with CH4 in the pores. The gas composition is nonuniformly distributed, and its viscosity μ is the dynamic parameter. As the gas is compressible, the pressure drops, and migration distance does not satisfy a linear relationship. Therefore, the gas transport does not conform to Darcy’s law. The mass transfer process and a multicomponent gas competitive adsorption were investigated theoretically and experimentally. The adsorption characteristics and gas compressibility determine the distribution of the gas components in pores and change the gas dynamic viscosity in different regions. The change in the gas dynamic viscosity in the channel is the direct reason for the nonlinear pressure gradient and gas flow curve. The permeability and gas component affect the degree of nonlinear deviation of the gas flow and pressure gradient curve. This affects the nonlinear deviation degree of the curve by changing the gas dynamic viscosity in the pore channel during displacement. The reasonable displacement pressure is the critical pressure (PO) through experimental and theoretical analysis.
... Some authors (Sinal and Lancaster, 1987;Luk and Apshkrum, 1996;Zhang et al., 2017Zhang et al., , 2021Zhou et al., 2018;Mojid et al., 2021;Hou et al., 2021Ranjith et al., 2019Song et al., 2019;Tao et al., 2020;Yin et al., 2016;Silva-Escalante et al., 2024) have been studied some waterless fracturing as an alternative for water usage in fracturing shale reservoirs as a sustainable method (Sayapov et al., 2023). These authors describe some advantages of CO 2 fracturing, as: ...
... • During the propagation, the CO 2 fracturing generates similar geometries to those obtained with Slickwater, however, the fracture width with CO 2 is higher, which is similar to what previously reported (Zhang et al., 2017(Zhang et al., , 2021Zhou et al., 2018;Mojid et al., 2021;Ranjith et al., 2019;and Song et al., 2019). The simulation results showed that the CO 2 fracturing yields an increase of 138% in average aperture and 190% in the maximum aperture compared to Slickwater. ...
In Mexico, the usage of water for fracturing has limited the national operator to develop the shale reservoirs. Water shortage in the northeast zone of this country is the main reason to look for a waterless fracturing technique as a sustainable method for development the unconventional resources in Mexico.
There are several studies to understand the advantages of CO2 as fracturing fluid in unconventional reservoirs. This work analyzes the resulting properties of propagated and effective fractures created by CO2 pure and with impurities (gasses and solids as "CO2-imp") compared to conventional Slickwater fractures for the shale gas reservoirs companied of economic analysis to study the effectiveness of CO2 fracturing as a sustainable development method for the Burgos Basin in Mexico. The CO2-imp represents the resulted composition from post combustion carbon capture technology typically used in the CO2 sources nearby to the Burgos Basin. An analysis of the effect of solid impurities (presented from chemical reaction in gases families) of CO2-imp during the fracturing propagation is provided.
Results of our study are based on fracturing and reservoir compositional simulations and economic analysis. During the propagation, the CO2 fracturing can promote similar fracture geometries as Slickwater, better fracture width and better effective properties (on the post-closure/flow-back period). The propped fracture properties are also studied to obtain production scenarios by reservoir modelling, resulting in the CO2-imp higher production behavior compared to Slickwater, showing the impact of water blockage. Results may show a relevant improved production with the use of CO2-imp of 510% of gas rate and 234% of cumulative gas production than with the use of Slickwater in a period of five years. Results of fracture propagation and post-closure in this work are consistent with those presented previously in the literature. Economic analysis is performed based on four type CO2-sources (thermoelectric power plant, combined cycle power plant, refinery and ammonia plant) and two transport scenarios (by truck tank and new line). Economic results show the CO2 fracturing by truck tank transport is more profitable compared to water fracturing, it is strongly related to production performance resulted from simulation in this work. In our work, the CO2 fracturing scenario based on CO2 transported by a new line is profitable under condition of developing five wells with the same cost and production performance.
... This attribute allows for smoother flow through minuscule pores and fractures within the reservoir rock, enabling deeper penetration into the rock matrix and generating fractures with enhanced tortuosity. This characteristic allows the injected fluid to effectively access the pre-existing fracture, and as the induced fracture propagates along its path, there is a significant reduction (~50%) in breakdown pressure (Zhang et al., 2017a;Li et al., 2019;Zhang et al., 2021;Feng and Firoozabadi, 2023), as summarized in Table 2. Laboratory tests have indicated that fractures created by CO 2 have higher tortuosity, as illustrated in Figure 2 (Song et al., 2019). Tortuosity pertains to the extent of deviation from a linear trajectory observed in fractures. ...
... The fracture morphology created by CO 2 and fracturing fluids. Reproduced with permission from Ref. Song et al. (2019), copyright (2019) Elsevier. ...
CO2, used as an environmentally friendly fracturing fluid, has encountered a bottleneck in development in recent years. Despite great efforts in research work, limited progress has been made in field applications. In this study, an extensive literature review of research work and field cases was performed to summarize the technical issues and challenges of CO2 fracturing. The key issues of CO2 fracturing were analyzed to reveal the gap between fundamental research and field operations. The effects of CO2 properties on fracture creation and proppant transport were synthetically analyzed to extract new common research orientations, with the aim of improving the efficiency of CO2 injection. The hydraulic parameters of CO2 fracturing were compared with those of water-based fracturing fluids, which revealed a theory-practice gap. By studying the developing trends and successful experiences of conventional fluids, new strategies for CO2 fracturing were proposed. We identified that the major theory-practice gap in CO2 fracturing exists in pump rate and operation scale. Consequently, the friction reducer, effects of flow loss (due to leak-off) and distribution (within fracture networks), and shear viscosity of thickened CO2 are key factors in improving both fracture propagation and proppant transport. By increasing the scale of injected CO2, the CO2 fracturing technique can be enhanced, making it an essential option for carbon capture, utilization, and storage (CCUS) to reduce carbon emissions and mitigate climate change.
... Hence, understanding these indices and their controlling factors is vital for the successful injection of fluid(s), such as CO 2 injection, which has gained a lot of momentum recently for many reasons including carbon geo-sequestration (CGS) from an environmental perspective and enhanced oil recovery (CO 2 -EOR) [23,24]. The CO 2 -EOR technique has proved to have substantial potential in increasing oil recovery in conventional and tight reservoirs [25]. Injecting CO 2 into oil reservoirs can be performed under miscible or immiscible conditions. ...
The microscopic structure of low-permeability tight reservoirs is complicated due to diagenetic processes that impact the pore-fluid distribution and hydraulic properties of tight rocks. As part of an ongoing study of carbon dioxide-enhanced oil and gas recovery (CO2-EOR/EGR) and CO2 sequestration, this research article adopts an integrated approach to investigate the contribution of the micropore system in pore-fluid distribution in tight sandstones. A new dimensionless number, termed the microscopic confinement index (MCI), was established to select the right candidate for microscopic CO2 injection in tight formations. Storativity and containment indices were essential for MCI estimation. A set of experiments, including routine core analysis, X-ray diffraction (XRD), scanning electron microscopy (SEM), mercury injection capillary pressure (MICP), and nuclear magnetic resonance (NMR), was performed on three tight sandstone rock samples, namely Bandera, Kentucky, and Scioto. Results indicate that the presence of fibrous illite acting as pore bridging in Bandera and Kentucky sandstone samples reduced the micropore-throat proportion (MTMR), leading to a significant drop in the micropore system confinement in Kentucky and Bandera sandstone samples of 1.03 and 0.56, respectively. Pore-filling kaolinite booklets reduced the micropore storativity index (MSI) to 0.48 in Kentucky and 0.38 in Bandera. On the other hand, the absence of fibrous illite and kaolinite booklets in Scioto sandstone led to the highest micropore system capability of 1.44 MTMR and 0.5 MSI to store and confine fluids. Therefore, Scioto sandstone is the best candidate for CO2 injection and storage among the tested samples of 0.72 MCI.
... El fracturamiento de fluidos base agua (WBF, por sus siglas en inglés) con baja viscosidad puede generar fracturas más largas y complejas que con WBF de alta viscosidad, con apuntalante o geles. Song et al. (2019) calcularon la superficie fracturada estimada, obteniendo que con WBF el área estimulada fue de 1934 cm 2 , mientras que con fluido base dióxido de carbono (CBF, por sus siglas en inglés) el área de fracturamiento fue de 3518 cm 2 , esto significa un beneficio en la producción debido a la presencia de un volumen estimulado de yacimiento (SRV) más complejo. describieron que la presión de fractura alcanzada es menor con el uso de CBF que con WBF, debido a la alta penetración en la matriz y la reducción de la resistencia y tenacidad de la roca. ...
... Experimental studies were conducted on the growth behavior of CO 2 -induced fractures in a layered tight sandstone formation (Zou et al., 2018). CO 2 fracturing was found to increase oil productivity in tight oil reservoirs by 4-to 20-fold (Song et al., 2019). Shale oil formations are less water-wet than sandstone formations due to their organics (kerogen) contents in rock matrix. ...
... LCO 2 is a nonpolar solvent that can extract organic matter (ethers, esters, lactones, and epoxides) from coal [34,35]. Compared with hydraulic fracturing, the LCO 2 viscosity (10%-16% of water) and surface tension are low, it is easier to connect the microcracks in the coal seam, and easier to penetrate and spread around the coal seam [36]. Heat-exchange occurs between the LCO 2 and coal in the pores and cracks, LCO 2 phase-transition vaporizes, and the gas pressure in the pores and cracks increases, which effectively improves the percolation power in coal cracks and increases the "driving" effect of free CH 4 [21]. ...
The high gas pressure, low permeability, and strong gas absorption of coal seams in China complicate gas extraction, severely restricting the efficient development of coalbed gas. Liquid CO2 (LCO2) has a dual effect of cracking and enhancing the permeability of coal rock, thus, enhancing gas recovery. In this study, experimental testing and comparative analyses were performed to analyze the LCO2 acidification of antireflection coal, for which reference and variable experimental groups were designed. The acidification effect was quantitatively analyzed by examining changes in the pH value of the reaction solution, mineral content of coal, and pore structure during the experimental process. The experimental results indicated that a higher pressure resulted in a greater amount of CO2 being dissolved and a stronger acidity of the reaction water sample. As the reaction time increased, the minerals in the coal gradually dissolved and more H⁺ ions in the solution were consumed. The calcite (carbonate) and illite (clay mineral) contents significantly decreased, which is the main reason for the change of coal pore structure. The minerals on the pore surface of coal react with (CO2–H2O) weak acid, which increases the development of pore branches, improves the complexity of coal pores, and roughens the pore surface. Acidification significantly increases the number of micropores (<10 nm) and small pores (10–100 nm) in coal; furthermore, pore development is simple, the surface is smooth, and the pore connectivity is improved, which makes this part of pores have fractal characteristics. CO2–H2O–coal acidification increases the pore volume corresponding to the CO2/CH4 gas slippage flow in coal and strengthens the mass and energy transfer of CO2/CH4 in coal. CO2 can enter more pores than CH4 and displace the adsorbed and free CH4 in the pores.
... It possesses advantageous characteristics such as high diffusivity, low viscosity, low surface tension, and controllable solubility. This unique nature of supercritical CO 2 finds extensive applications in oil displacement technology and fracturing technology [9], effectively addressing the limitations associated with hydraulic fracturing [10,11]. These limitations include excessive water consumption, clay swelling, reservoir damage caused by residual working fluids, and inadequate flowback leading to groundwater pollution [12,13]. ...
Supercritical carbon dioxide (CO2) has extremely important applications in the extraction of unconventional oil and gas, especially in fracturing and enhanced oil recovery (EOR) technologies. It can not only relieve water resource wastage and environmental pollution caused by traditional mining methods, but also effectively store CO2 and mitigate the greenhouse effect. However, the low viscosity nature of supercritical CO2 gives rise to challenges such as viscosity fingering, limited sand–carrying capacity, high filtration loss, low oil and gas recovery efficiency, and potential rock adsorption. To overcome these challenges, low–rock–adsorption thickeners are required to enhance the viscosity of supercritical CO2. Through research into the literature, this article reviews the solubility and thickening characteristics of four types of polymer thickeners, namely surfactants, hydrocarbons, fluorinated polymers, and silicone polymers in supercritical CO2. The thickening mechanisms of polymer thickeners were also analyzed, including intermolecular interactions, LA–LB interactions, hydrogen bonding, and functionalized polymers, and so on.
... In response to these limitations, supercritical CO 2 has emerged as an alternative waterless fracturing fluid, exhibiting significant potential. Compared to traditional water-based fracturing fluid, the use of supercritical CO 2 as a working fluid can significantly enhance oil and gas recovery, reduces consumption of water resources, and facilitate carbon sequestration to effectively promote carbon emission reduction (Haq et al., 2023;Middleton et al., 2015;Mojid et al., 2021;Song et al., 2019;Yang et al., 2022). The promising prospects of supercritical CO 2 fracturing have led to a growing interest in related research in recent years. ...
... True-triaxial testing equipment was employed to simulate the hydraulic fracturing process [49]. To forestall shear stress between the pressure platen and the sample, a thin layer of Vaseline and Teflon was attached to both sides of the samples. ...
Fracture–cavity carbonate reservoirs account for a considerable proportion of oil and gas resources. Because of the complicated relationships between cavities, fractures and pores in these reservoirs, which are defined as cavity clusters, fracturing technology is employed to enhance their hydrocarbon productivity. However, almost all previous studies have just considered the effect of a single natural cavity or fracture on the propagation of a hydraulic fracture; therefore, the mechanism by which a hydraulic fracture interacts with a cavity cluster needs to be clarified. In this study, cavity clusters with different distributions were accurately prefabricated in synthetically made samples, and large-scale simulation equipment was employed to systematically perform fracturing experiments considering different horizontal differential stress levels. Meanwhile, the hydraulic fracture propagation behaviors were comprehensively analyzed through fracture morphology, fracturing curves, the complexity of the fracture network and acoustic emission monitoring. It was found that a natural fracture with a smaller approach angle is favorable in guiding a hydraulic fracture to a cavity. The fracturing curves were divided into the following four types: frequent fluctuations with “step-like” shapes, great fluctuations with slightly lower closure pressure, fluctuations with obviously lower closure pressure, and little fluctuations with obviously lower closure pressure. And different cavity cluster distributions play a dominant role in the complexity of generated hydraulic fracture networks. In addition, AE energy was used to judge the ease of crossing the cavity. The above findings indicated that for the actual exploration and exploitation of carbonate reservoirs, the geological exploration of different fracture–cavity structures in reservoirs would be required, and targeted fracturing engineering designs need to be carried out for different fracture–cavity carbonate reservoirs.
... Due to its low viscosity, high density, and elevated diffusivity, supercritical CO 2 (Sc-CO2) is considered to be an ideal waterless fracturing fluid for shale gas development [11]. Compared with hydraulic fracturing, using Sc-CO 2 as a fracturing fluid can lower the breakdown pressure of shale reservoirs and generate more complex and conductive fracture networks [12]. Zhang et al. conducted physical simulation experiments and found that using Sc-CO 2 as a fracturing fluid can reduce the pressure required to initiate fractures by more than 50 % compared to hydraulic fracturing [13]. ...
Injecting CO2 into shale gas formations to improve recovery and sequestrate CO2 is regarded as a promising technology. Understanding the softening behavior of shale induced by CO2 injection is crucial for the engineering decision of shale gas development and CO2 geo-sequestration. In this study, the softening behavior of shale induced by CO2 injection was investigated based on nanoindentation. Emphasis was placed on analyzing the differences in shale softening behavior in the absence and presence of water. CO2 injection caused alteration of shale mineral composition and mechanical properties. The contents of quartz and muscovite increased after treatment, while albite, anorthite, and kaolinite decreased. The nanoindentation results were analyzed using the Gaussian mixture model and upscaled using Mori-Tanaka model. Three mechanical phases (i.e. soft phase, intermediate phase, and stiff phase) were identified through Gaussian mixture model. Under the condition of CO2 treatment, both the hard and soft phases softened, while the intermediate phase did not. Under the condition of CO2+H2O treatment, all three phases - hard, intermediate, and soft - experienced significant softening. The macroscale elastic modulus of shale sample was estimated through Mori-Tanaka method. Compared with untreated sample, the decrease in macroscale elastic modulus of CO2 treated sample is 10.92 %, and that of CO2+H2O treated sample is 45.76 %. The results of this study show that shale softening induced by CO2 injection is more severe in the presence of water than that in the absence of water.
... CO 2 has demonstrated the ability to generate a more complex fracture network than that generated with water exhibiting more extended fractures than those obtained with water. Also, CO 2 can stimulate microfractures more efficiently than water due to its high leak-off capacity (Song et al., 2019;Ranjith et al., 2019;Zhou et al., 2019). Multiple branch fractures generated with CO 2 have shown the presence of rock micro-particles, mainly in shale samples, which act as proppants, reaching fracture apertures of 2 to 5 times greater than those obtained by WBFF . ...
This work aims to evaluate the fracture geometry and production scenarios comparing several fracturing fluids, such as slickwater and carbon-based fracturing fluids (CBFF), including two binary mixtures as approximations to anthropogenic CO2 resulting from carbon capture (oxyfuel, pre-combustion, and post-combustion). Reservoir flow modeling simulations show that CBFF is the best potential waterless fracturing fluid option for fracturing unconventional shale reservoirs in the Burgos Basin.
We conducted fracturing simulations to obtain the fracture geometry resulting from pure CO2, gelled CO2, foamed CO2, as well as the binary mixtures CO2 (95% mol)-N2 (5% mol), and CO2 (95% mol)-H2 (5% mol) and compared the results to conventional slickwater fracturing. Data and information for this study come from a gas well in the Burgos Basin in Mexico. A compositional fracturing simulation model is used to obtain the fracture geometry and the conditions under which the CO2 fracturing would be optimal based on a sensitivity analysis of the critical parameters described in this work. We created a reservoir simulation model to generate production scenarios and compare the well performance of wells fractured with pure CO2 and slickwater. The impact of water blockage effects on well productivity is shown to be important.
Results show that pure CO2, CO2-N2, and CO2-H2 create fracture geometries that are similar to slickwater fracturing. Pure CO2 provides the highest production due to the absence of water blockage effects. Other carbon-based fracturing fluids also represent an opportunity for implementing CO2 to optimize well performance reducing water blockage and water consumption for sustainably fracturing conventional and unconventional reservoirs.
CO2 fracturing has been recognized for its significant advantages in enhancing petroleum recovery. In this study, we establish a finite volume method (FVM)-based phase-field model to simulate CO2 fracturing in poroelastic media, accounting for fluid property variations with temperature and pressure. The porous medium is modeled using classical Biot poroelasticity theory, while fracture behavior is described through a phase-field framework. The phase field acts as an interpolation function to smoothly transition properties between the fracture and reservoir regions. The governing equations are discretized using an implicit cell-centered FVM and solved via an iterative staggered scheme. CO2 thermophysical properties are updated via the Peng–Robinson equation of state and the Lohrenz–Bray–Clark viscosity model. The framework is verified through a 2D notched specimen subjected to injection of water and CO2. It is then applied to investigate fracture propagation in both homogeneous and heterogeneous shale reservoirs. For the homogeneous cases, we analyze the effects of horizontal principal stress differences and natural fracture approach angles. For the heterogeneous reservoirs, we examine how natural fracture orientation and interlayer elastic modulus contrast affect fracture morphology and propagation. This study demonstrates the robustness of the proposed framework in capturing complex fracture behavior, offering insights into optimizing CO2 fracturing for unconventional gas and oil extraction.
Global demands for carbon emission reductions and the shift towards a green, sustainable energy sector have highlighted the secure and steady injection of CO2 into underground layers as a key component of carbon storage initiatives. Unlike geological storage in high-permeability reservoirs, it is crucial to clarify the migration and reservoir response of CO2 in low-permeability geological reservoirs. To address this, core permeability experiments and low-rate injection experiments were designed, and the physical parameters and induced behaviors of sandstone samples were analyzed using wave velocity measurements, CT scanning, and SEM technology. The results show that: (1) After CO2 is injected into low-permeability sandstone samples, the porosity and pore size of the rock increase significantly. (2) CO2 injection into low-permeability sandstone can induce small-scale fracture propagation, which elucidates the microscopic mechanisms behind microseismic events when CO2 is injected at a low rate. (3) The events monitored during CO2 injection into low-permeability reservoirs directly characterize the fluid migration area. CO2 injection experiments combined with PFC-DEM numerical simulations reveal the microscopic mechanisms of CO2 penetration and fracturing in low-permeability reservoirs with low displacement injection. These findings provide a basis for predicting the diffusion and migration patterns of CO2 during carbon storage, as well as its fracturing behavior. The characterization of fracture distribution contributes to the detailed description and interpretation of microseismic monitoring data, helping to prevent CO2 leakage due to unpredictability in engineering, thereby ensuring the effective implementation of carbon sequestration projects and supporting ecological safety monitoring and protection.
Fracturing shale gas reservoirs with carbon dioxide (CO2) represents an efficient technique in the extraction process. Enhancing the effectiveness of hydrofracturing in these reservoirs necessitates a precise analysis of their heterogeneous nature, mandating the use of 3D reservoir modelling. This modelling approach demonstrates the application of reservoir simulation techniques, crucial for forecasting successful fracturing methods in shale gas recovery. Conducting multi-stage fracturing tests on unconventional reservoirs using this model allows for the assessment of heterogeneity and variations in fracture distance, considering factors like fracture half-length, spacing, and conductivities. Employing CO2 as a fracturing fluid, a simulation study explores diverse conditions. The findings from simulation and modelling indicate a notable enhancement in shale gas recovery rates, exhibiting an increase ranging between approximately 3–7%. These improvements are linked to alterations in fracture half-length, spacing, and the number of fractures.
The continuous use of fossil fuels has a huge impact on climate change because they release CO2, which is a major greenhouse gas that causes 70–75% of global warming. Shale reserves could be used to store CO2 to lower greenhouse gas emissions. This could happen mostly through adsorbed gas, which can make up about 85% of all shale gas. It is important to fully understand the CO2 adsorption processes in shale, especially when using isothermal models, to get accurate estimates of storage capacity and predictions of how shale will behave. This work examines the application of several isothermal models, including Langmuir, Freundlich, Brunauer–Emmett–Teller, Dubinin–Radushkevich, Dubinin–Astakhov, Sips, Toth, and Ono-Kondo lattice models, to explore the adsorption of CO2 on shale formations. The aim of this research work is to assess the efficiency of these models in forecasting CO2 adsorption in different shale samples with specific mineral compositions, total organic content (TOC), surface areas, and pore geometry at 298 K and up to 2 MPa. This review provides a state-of-the-art knowledge on the constraints of existing models and proposes adaptations, such as integrating density-dependent correction factors and hybrid modeling techniques, to enhance precision during numerical simulation work. Furthermore, the possible incorporation of molecular dynamic (MD) simulations with experimental data is suggested to improve the understanding of the CO2 adsorption in the geological rock at the molecular scale. The results emphasize the need for future studies to concentrate on the improvement of models and empirical validation to more accurately forecast the storage behavior of CO2 in shale formations at resevoir conditions.
Supercritical carbon dioxide (SC-CO2) fracturing has emerged as a promising non-blasting rock fracturing method within the carbon capture, utilization, and storage (CCUS) portfolio. Understanding the evolution of global fracture network, which is a complex and dynamic process, is essential for enhancing fracturing effectiveness. However, traditional research methods have been inadequate for dynamically and quantitatively tracking and characterizing the development of these networks. In this study, SC-CO2 fracturing experiments and active source acoustic emission monitoring tests were conducted under three different confining pressures (CPs) caused by the reverse conditions at different burial depths. The characteristic parameters of global fracture network evolution were analyzed using coda wave signals, including frequency, transmissivity, relative velocity (dv/v), and decorrelation coefficient (DC). The relationships between these parameters and the combined effects of CPs and fracturing pressure were established, and the mechanisms of global fracture network evolution were discussed. The results indicate that the microscopic mechanism of SC-CO2 fracturing involves fissure tip extension driven by expansional energy from SC-CO2 phase transition, which is influenced by the compression-shear effect induced by CPs. Additionally, the compression-shear effect governs the developmental rate and direction of the global fracture network, determining the final failure pattern. The combined influence of CPs and fracturing pressure on all investigated parameters was linked to an increase in coda wave travel time, resulting in a decay trend in frequency, transmissivity, and dv/v, while the DC exhibited an increasing trend. This study introduces a novel method for monitoring the SC-CO2 fracturing process, enhances the quantitative characterization of global fracture network evolution, and promotes the application of SC-CO2 fracturing in situ.
Economic and population growth is the main cause of the continuous sharp increase in energy demand. As a result, new energy sources like renewable energy and unconventional gas have attracted a lot of attention. Recent advancements in hydraulic and horizontal fracture have made shale gas a significant worldwide energy source. The extraction of shale gas from the rock requires a significant volume of water, which is utilized as a fracturing fluid in this process. However, the issues surrounding the use and disposal of water raise grave worries about potential negative effects and have also made complex water management measures necessary. This chapter offers an alternate approach to lowering freshwater usage by using CO2 captured from power plants as a fracturing fluid. To account for system uncertainty, this project implemented a mathematical programming approach to create networks of water and CO2 that are related to shale gas hydraulic fracture operations (water availability, CO2 generation, and flowback water based on a horizon time). The presented formulation demonstrates strategic planning that reduces the total annual cost (TAC) while considering the need for water, the production and capture of CO2, the equipment’s capacity for treatment technologies, transportation costs, storage units, and disposal. To demonstrate how the presented approach can be applied, an example problem is provided. The model shows that when the fracking fluid’s CO2 content rises, the TAC rises but the amount of freshwater needed falls. Additionally, since using water is less expensive than using CO2, freshwater availability is the primary factor affecting the TAC.
On a global scale, shale oil/gas has become an important alternative energy source for conventional oil and gas. The potential advantages of supercritical CO2 (ScCO2) make it an ideal alternative to hydraulic fracturing, used for shale reservoir transformation and production increase while also promoting the geological storage of CO2, which is in-line with today’s carbon capture, utilization, and storage technology and helps to address the challenges of global climate change.
To further study the fracture propagation and optimization of a complex fracture network (CFN) in ScCO2 fracturing under complex geological conditions using the cohesive module of ABAQUS to establish a fluid structure coupling model and completing indoor and field experimental verification, we introduce the global embedded cohesion zone model (CZM) combined with Python to generate two natural-fracture (NF) distribution models, conjugate and power law, to establish a dispersed mesh model. Based on this model, we studied the fracture propagation problem of ScCO2 fracturing under different engineering and geological conditions. The simulation results will be used as data-driven data to establish an optimization model of the random forest-particle swarm optimization algorithm (RF-PSO) and optimize the CFN.
Research has shown that (1) ScCO2 is more inclined to pass through NFs and propagate in the rock matrix, and hydraulic fractures (HFs) combine better with NFs. Compared with hydraulic fracturing, ScCO2 fracturing has significant advantages (only the fracture width is lower than hydraulic fracturing, its initiation pressure and fracture length are much better than hydraulic fracturing, and there are more small fractures, making it easier to form a CFN). (2) During the process of fracture propagation, once dominant fractures form, the trend of the “Matthew effect” is inevitable. The process of fracture propagation is influenced by multiple factors, especially the distribution of NFs; the larger the reservoir filtration coefficient is, the more ScCO2 fracturing fluid that is lost, which is more unfavorable for fracturing construction. While maintaining the same amount of fracturing fluid injection, as the displacement increases, the fracture complexity increases, and the fracturing control range expands. Compared with other parameters, the effect of fracturing fluid temperature (FFT) on the expansion of ScCO2 fracturing fractures is not significant. (3) The established RF-PSO optimization model has an error of 2.89%, which can well adapt to CFN optimization problems under complex NF conditions and reduce uncertainty. We propose in this article a research method for fracture network optimization from fracture modeling, dynamic simulation, and optimization modeling. By combining numerical simulation and machine learning, the CFN optimization design of ScCO2 fracturing under CFN conditions is achieved, providing a research approach for the optimization of fracturing in fractured reservoirs.
Hydraulic fracturing can create a fracture network that enables fluid penetration of a basalt formation with otherwise low porosity, offering a site for rapid CO 2 mineralization sequestration. Supercritical carbon dioxide (SC-CO 2 ) is a promising fracturing fluid with unique properties, making it well-suited for unconventional oil and gas reservoir stimulation. In this study, experiments of fracturing with water and SC-CO 2 were conducted under different injection schemes and formation temperatures. The frackability of basalts was investigated from the perspective of breakdown pressure and fracture morphology. The findings revealed that SC-CO 2 fracturing with a low pressurization rate could become an optimized option for enhancing the stimulated effect. The potential of carbon sequestration was roughly estimated based on the area of induced fractures, suggesting that fostering a developed fracture network would aid in the in-situ mineralization and storage of carbon. The variation of element composition obtained from basalt slices containing fractures induced by SC-CO 2 under different reaction conditions verified the role of water participation and time scale in the mineralization effect.
Intensive growth of geological carbon sequestration has motivated the energy sector to diversify its storage portfolios, given the background of climate change mitigation. As an abundant unconventional reserve, shale gas reservoirs play a critical role in providing sufficient energy supply and geological carbon storage potentials. However, the low recovery factors of the primary recovery stage are a major concern during reservoir operations. Although injecting CO2 can resolve the dual challenges of improving the recovery factors and storing CO2 permanently, forecasting the reservoir performance heavily relies on reservoir simulation, which is a time-consuming process. In recent years, pioneered studies demonstrated that using machine learning (ML) algorithms can make predictions in an accurate and timely manner but fails to capture the time-series and spatial features of operational realities. In this work, we carried out a novel combinational framework including the artificial neural network (ANN, i.e., multilayer perceptron or MLP) and long short-term memory (LSTM) or bi-directional LSTM (Bi-LSTM) algorithms, tackling the challenges mentioned before. In addition, the deployment of ML algorithms in the petroleum industry is insufficient because of the field data shortage. Here, we also demonstrated an approach for synthesizing field-specific data sets using a numerical method. The findings of this work can be articulated from three perspectives. First, the cumulative gas recovery factor can be improved by 6% according to the base reservoir model with input features of the Barnett shale, whereas the CO2 retention factor sharply declined to 40% after the CO2 breakthrough. Second, using combined ANN and LSTM (ANN-LSTM)/Bi-LSTM is a feasible alternative to reservoir simulation that can be around 120 times faster than the numerical approach. By comparing an evaluation matrix of algorithms, we observed that trade-offs exist between computational time and accuracy in selecting different algorithms. This work provides fundamental support to the shale gas industry in developing comparable ML-based tools to replace traditional numerical simulation in a timely manner.
An analysis of the fracture geometry resulting from fracturing with carbon dioxide base fluids (CBF), such as pure, gelled, foamy and binary mixture of CO2 (95% mol) with N2 (5% mol) and H2 (5% mol) compared to hydraulic fracturing with water-based fluid (WBF), such as slickwater, is performed using specialized software (EFRAC). The impure components used for modeling are based on the main components in anthropogenic CO2 streams. Factors such as: fracture height and length, fracture width, the fracture volume, and the filtered volume (leaked off), temperature and density of the fracture fluid, are analyzed. Finally, a sensitivity analysis of parameters such as the Poisson ratio, Young modulus, pumping rate, reservoir net-pay and reservoir temperature are performed to study the optimization of fracture geometry. The results show that CBF and binary mixture of CO2 fracturing produce results similar to WBF fracturing in terms of fracture geometry. This encourages the study of CO2 fracturing using mixtures from CO2 capture plants containing high levels of CO2 with low levels of gas impurities to substitute the water in conventional fracturing treatment.
Utilizing supercritical CO2 instead of water for shale gas stimulation has been proposed as a potential alternative. Understanding the scCO2–shale interaction during fracturing and its response to micromechanical as well as mineralogical properties of the rock is crucial to improve its application. To achieve this goal, dry scCO2 soaking experiments were carried out on two distinct shale samples (Eagleford and Mancos) for a 24 h duration. Multiple characterization techniques, including nanoindentation, scanning electron microscopy (SEM), energy-dispersive spectroscopy, and X-ray diffraction, were employed to understand the micromechanical and physical alterations to the two rocks caused by the short-term interaction with scCO2. The results of the nanoindentation indicate that the short-term interaction of scCO2 has a higher impact on the mechanical properties of Eagleford than the Mancos shale. This is due to the calcareous nature of the Eagleford rocks, composed of around 78% carbonate minerals. Nanoscale analysis of specific mineral-rich sites on the surface of both rocks reveals that the micromechanical response to the exposure of scCO2 is different for each mineral. The hierarchy of indentation modulus reduction is carbonate minerals, followed by clay, organic matter, and quartz. SEM images after CO2 exposure showed calcite etching along the calcite-accumulated areas, blurring of clay crystals in clay-dominated regions, and the generation and extension of the microcracks along the pre-existing fractures. Overall, the study’s results suggest that dry scCO2 exposure can alter the properties of both Eagleford and Mancos shale even during short-term exposure (e.g., fracturing operation). The formation of microcracks and a reduction in strength could potentially aid scCO2 fracturing by reducing the pressure needed for rock breakdown and creating more defined microfractures along the primary fracture planes. This, together with the dissolution and etching of minerals, has the potential to enhance the rock’s porosity and permeability, thereby improving the performance of scCO2 fracturing. The extent and characteristics of these modifications and their distribution within a rock will rely on heterogeneity and the arrangement of various minerals in it. Therefore, such interactions should be carefully considered along with the nature of the targeted shale formation when contemplating the use of CO2-based fracturing in shale reservoirs.
Carbon dioxide (CO2) emissions present one of the world's most pressing issues as a primary drive for climate change. This requires a viable solution through capture and storage in geological carbon sinks including depleted or mature hydrocarbon formations, coal seams and aquifers. CO2-enhanced oil recovery (CO2-EOR) poses an economically feasible prospect for the industry owing to the opportunity to recover trapped hydrocarbons and already existing exploration technologies. However, limitations exist in the form of availability of abundant CO2 and capital cost, rather than the availability of reservoir candidates. The successful application of Carbon Capture and Sequestration (CCS) through CO2-EOR requires the investigation of rock-fluid data, reservoir screening information, and wettability behavior. In addition, it is necessary to pursue interdisciplinary engagement and identify safe CO2 storage sites; whilst relying on extensive knowledge of rock geology and robustness of transportation infrastructure. This review study encompasses a holistic investigation on CO2 mitigation via EOR utilization, the technical aspects, environmental impact and persisting challenges with the aid of earlier lab-scale experiments and field-scale studies. The mechanisms of petroleum resource displacement have been reported in detail, along with storage media description for CCS. Emphasis is placed on the importance of research and development (R & D) activities to highlight a roadmap to attain permanent geo-storage of CO2 during hydrocarbon recovery.
Subsurface carbon dioxide (CO2) storage is being widely studied as a suitable solution for reducing greenhouse emissions. Shales are regarded as effective storage rocks and caprock seals of stored CO2; however, the induced CO2/shale interactions remain a key challenge that can affect storage and sealing behaviors. Despite the current devotion directed toward understanding the CO2/shale geochemical interactions, only limited work is available on the reactivity of CO2 to shale rocks with high total organic carbon (TOC) contents. In this work, we experimentally investigate the CO2/rock geochemical reactions for high-TOC shales and address the impact on the surface morphology and storage potential. A high-TOC shale sample (14.6 wt %) was treated with CO2 at 75 °C and 1400 psi for 60 days, and various analytical methods, including X-ray diffraction, TOC analysis, scanning electron microscopy, and energy-dispersive X-ray analysis, were performed. The results indicate a minor alteration in mineral composition after CO2 treatment, suggesting that mineral dissolution/precipitation induced by CO2 was very low. The dissolution behavior of calcite indicates that carbonate solubility in shales in the presence of CO2 is likely to occur, which in the long term can provide an efficient trapping mechanism through mineralization. The contents and distribution of organic matter on the shale surface did not exhibit a significant change after CO2 treatment, suggesting that decomposition/oxidation of organic matter was not sufficient during the treatment duration. We observed only minor changes in the pore distribution of the volume after CO2 treatment, indicating that neither pore expansion nor shrinkage occurred. The obtained results confirm the stability and suitability of high-TOC shales for CO2 subsurface storage applications under the experimental conditions. Future works can build on the obtained results of this experimental work to assist in the understanding of the nature of shale reactivity to CO2.
Massive hydraulic fracturing requires an enormous consumption of water and introduces many potential environmental issues. In addition, water-based fluid tends to be trapped in formations, reducing oil/gas-phase relative permeability, and causes clay-mineral swelling, which lowers absolute permeability. Carbon dioxide (CO2) is seen as a promising alternative working fluid that poses no formation-damage risk, and it can stimulate more-complex and extensive fracture networks. However, very little, if any, extant research has quantitatively analyzed the effectiveness of CO2 fracturing, except for some qualitative fracturing experiments that are based on acoustic emissions. In this study, we systematically examine water and CO2 fracturing, and compare their performance on the basis of a rigorously coupled geomechanics and a fluid-heat-flow model. Parameters investigated include fluid viscosity, compressibility, in-situ stress, and rock permeability, illustrating how they affect breakdown pressure (BP) and leakoff, as well as fracturing effectiveness. It is found that (1) CO2 has the potential to lower BP, benefiting the propagation of fractures; (2) water fracturing tends to create wider and longer tensile fractures compared with CO2 fracturing, thereby facilitating proppant transport and placement; (3) CO2 fracturing could dramatically enhance the complexity of artificial fracture networks even under high-stress-anisotropy conditions; (4) thickened CO2
tends to generate simpler fracture networks than does supercritical CO2 (SC-CO2), but still more-complex fracture networks than fresh water; and (5) the alternative fracturing scheme (i.e., SC-CO2 fracturing followed by thickened-CO2 fracturing) can readily create com- plex fracture networks and carry proppant to keep hydraulic fractures open. This study reveals that, for intact reservoirs, water-based fracturing can achieve better fracturing performance than CO2 fracturing; however, for naturally fractured reservoirs, CO2 fracturing
can constitute an effective way to stimulate tight/shale oil/gas reservoirs, thereby improving oil/gas production.
Exploitation of shale gas by hydraulic fracturing (fracking) is highly controversial and concerns have been raised regarding induced risks from this technique. As part of the EU-funded SHEER Project, a shallow aquifer used for drinking water, overlying a zone of active shale-gas fracking, has been monitored for more than a year. Early results reveal the functioning of the shallow aquifer and hydrochemistry, focusing on the identification of potential impacts from the shale gas operation. This stage is an essential precursor to modeling impact scenarios of contamination and to predict changes in the aquifer.
We consider the feasibility of a novel Carbon Capture, Utilization and Storage (CCUS) concept that consists in producing oil and gas from hydrocarbon-rich shales overlying deep saline aquifers that are candidates for CO2 storage. Such geological overlapping between candidate aquifers for CO2 storage and shale plays exists in several sedimentary basins across the continental US. Since CO2 reaches the storage formation at a lower temperature than the in-situ temperature, a thermal stress reduction occurs, which may lead to hydraulic fracturing of the caprock overlying the aquifer. In this work, we use a thermo-hydro-mechanical approach for modelling a caprock-aquifer-baserock system. We show that hydraulic fracturing conditions are induced within the aquifer by thermal stress reduction caused by cooling and that hydraulic fractures eventually propagate into the lower portion of the shale play. Nonetheless, fracture height of penetration in the caprock is considerably short after 10 years of injection, so the overall caprock sealing capacity is maintained. To maximize the benefit of the proposed CCUS method, CO2 injection should be maintained as long as possible to promote the penetration depth of cooling-induced hydraulic fractures into organic-rich shales. Though drilling a horizontal well in the lower portion of the shale to produce hydrocarbons from the induced hydraulic fractures may not be technically feasible, hydrocarbons can still be produced through the injection well. The production of hydrocarbons at the end of the CO2 storage project will partly compensate the costs of CCS operations.
Hydrocarbon recovery from unconventional reservoirs (shale gas) is debated due to its environmental impact and uncertainties on its predictability. But a lack of scientific knowledge impedes the proposal of reliable alternatives. The requirement of hydrofracking, fast recovery decay and ultra-low permeability-inherent to their nanoporosity-are specificities of these reservoirs, which challenge existing frameworks. Here we use molecular simulation and statistical models to show that recovery is hampered by interfacial effects at the wet kerogen surface. Recovery is shown to be thermally activated with an energy barrier modelled from the interface wetting properties. We build a statistical model of the recovery kinetics with a two-regime decline that is consistent with published data: a short time decay, consistent with Darcy description, followed by a fast algebraic decay resulting from increasingly unreachable energy barriers. Replacing water by CO2 or propane eliminates the barriers, therefore raising hopes for clean/efficient recovery.
Slick-water fracturing is the most routine form of well stimulation in shales; however N
2
, LPG and CO
2
have all been used as “exotic” stimulants in various hydrocarbon reservoirs. We explore the use of these gases as stimulants on Green River shale to compare the form and behavior of fractures in shale driven by different gas compositions and states and indexed by breakdown pressure and the resulting morphology of the fracture networks. Fracturing is completed on cylindrical samples containing a single blind axial borehole under simple triaxial conditions with confining pressure ranging from 10 to 25 MPa and axial stress ranging from 0 to 35 MPa (σ
1 > σ
2 = σ
3). Results show that: (1) under the same stress conditions, CO
2
returns the highest breakdown pressure, followed by N
2
, and with H
2
O exhibiting the lowest breakdown pressure; (2) CO
2
fracturing, compared to other fracturing fluids, creates nominally the most complex fracturing patterns as well as the roughest fracture surface and with the greatest apparent local damage followed by H
2
O and then N
2
; (3) under conditions of constant injection rate, the CO
2
pressure build-up record exhibits condensation between ~5 and 7 MPa and transits from gas to liquid through a mixed-phase region rather than directly to liquid as for H
2
O and N
2
which do not; (4) there is a positive correlation between minimum principal stress and breakdown pressure for failure both by transverse fracturing (σ
3axial) and by longitudinal fracturing (σ
3radial) for each fracturing fluid with CO
2
having the highest correlation coefficient/slope and lowest for H
2
O. We explain these results in terms of a mechanistic understanding of breakdown, and through correlations with the specific properties of the stimulating fluids.
Fracturing technologies for shale gas production were developed mainly in the USA and are currently being adapted to geological conditions and environmental requirements in other countries. This paper presents literature on theoretical and practical aspects of gas production from shale with the emphasis placed on alternatives to hydraulic fracturing. Technical and environmental aspects of non-aqueous fracturing technologies are also considered.
Significance
New techniques of high-volume hydraulic fracturing (HVHF) are now used to unlock oil and gas from rocks with very low permeability. Some members of the public protest against HVHF due to fears that associated compounds could migrate into aquifers. We report a case where natural gas and other contaminants migrated laterally through kilometers of rock at shallow to intermediate depths, impacting an aquifer used as a potable water source. The incident was attributed to Marcellus Shale gas development. The organic contaminants—likely derived from drilling or HVHF fluids—were detected using instrumentation not available in most commercial laboratories. More such incidents must be analyzed and data released publicly so that similar problems can be avoided through use of better management practices.
Abstract Hydraulic fracturing of shale formations in the United States has led to a domestic energy boom. Currently, water is the only fracturing fluid regularly used in commercial shale oil and gas production. Industry and researchers are interested in non-aqueous working fluids due to their potential to increase production, reduce water requirements, and to minimize environmental impacts. Using a combination of new experimental and modeling data at multiple scales, we analyze the benefits and drawbacks of using CO2 as a working fluid for shale gas production. We theorize and outline potential advantages of CO2 including enhanced fracturing and fracture propagation, reduction of flow-blocking mechanisms, increased desorption of methane adsorbed in organic-rich parts of the shale, and a reduction or elimination of the deep re-injection of flow-back water that has been linked to induced seismicity and other environmental concerns. We also examine likely disadvantages including costs and safety issues associated with handling large volumes of supercritical CO2. The advantages could have a significant impact over time leading to substantially increased gas production. In addition, if CO2 proves to be an effective fracturing fluid, then shale gas formations could become a major utilization option for carbon sequestration.
Hydraulic fracturing and horizontal drilling has led to a shale gas energy boom in the United States. In addition to decreasing domestic energy costs, shale gas production has substantially reduced domestic CO2 emissions, largely due to natural gas displacing coal-fired electricity generation. Water is the principal component of working fluids used for commercial hydraulic fracturing, along with other constituent chemicals and substances to enhance fracture propagation/longevity and propping agent (e.g., sand) transport. Industry, policy makers, and other stakeholders are aware of potential disadvantages of aqueous fracturing fluids, including water scarcity, environmental impact from constituent chemicals, and poor fracture performance. To address these problems we are undertaking a study using supercritical CO2 as a replacement working fluid. Supercritical CO2 has many potential benefits and drawbacks compared with water as a fracturing fluid; it may increase gas production through several coupled processes including enhanced fracturing, reduced flow blocking, and miscibility with in-place hydrocarbons, as well as challenges such as economics, resource availability, and assurances that the CO2 is safely sequestered in the target formation. Through a combination of basic experiments, modelling, and historical research, we formally address these issues.
Natural gas is considered a cleaner and lower-emission fuel than coal, and its high abundance from advanced drilling techniques has positioned natural gas as a major alternative energy source for the U.S. However, each ton of CO2 emitted from any type of fossil fuel combustion will continue to increase global atmospheric concentrations. One unique approach to reducing anthropogenic CO2 emissions involves coupling CO2 based enhanced gas recovery (EGR) operations in depleted shale gas reservoirs with long-term CO2 storage operations. In this paper, we report unique findings about the interactions between important shale minerals and sorbing gases (CH4 and CO2) and associated economic consequences. Where enhanced condensation of CO2 followed by desorption on clay surface is observed under supercritical conditions, a linear sorption profile emerges for CH4. Volumetric changes to montmorillonites occur during exposure to CO2. Theory-based simulations identify interactions with interlayer cations as energetically favorable for CO2 intercalation. In contrast, experimental evidence suggests CH4 does not occupy the interlayer and has only the propensity for surface adsorption. Mixed CH4:CO2 gas systems, where CH4 concentrations prevail, indicate preferential CO2 sorption as determined by in situ infrared spectroscopy and X-ray diffraction techniques. Collectively, these laboratory studies combined with a cost-based economic analysis provide a basis for identifying favorable CO2-EOR opportunities in previously fractured shale gas reservoirs approaching final stages of primary gas production. Moreover, utilization of site-specific laboratory measurements in reservoir simulators provides insight into optimum injection strategies for maximizing CH4/CO2 exchange rates to obtain peak natural gas production.
The feasibility of storing carbon dioxide (CO2) in geologic formations as a means to mitigate global climate change is being evaluated around the globe. One option that has received limited attention is to store CO2 in shale formations that are currently productive unconventional shale gas plays. While CO2 trapping mechanisms in saline aquifers are primarily structural, capillary, solubility, and mineral trapping, the mechanisms are fundamentally different in gas shales, and CO2 adsorption onto organic materials and clay minerals plays a key role. Shale gas formations have a high content of organic matter that may store significant amounts of adsorbed natural gas, ranging from 20% to 80% of original-gas-in-place (OGIP). Laboratory and theoretical calculations suggest that CO2 is adsorbed preferentially over methane (CH4) onto the organics and could displace the methane (with up to a 5:1 ratio by molecule). This mechanism could be the basis of a new method of carbon capture, utilization, and storage (CCUS) that stores the CO2 in gas shales with the potential added benefit of enhanced gas recovery (EGR).
The injection of fluid into a rock mass results in variations of effective stresses that sometimes generate induced seismicity. These effective stress field variations depend on the diffusion process, which depends, in turn, on the magnitude of the pore pressure variation relative to the total stress. Four diffusion mechanisms are distinguished: diffusion through a poroelastic rock mass, and diffusion in preferential directions controlled either by slip along preexisting fractures, or by the development of fresh shear zones, or by hydraulic fracturing. More importantly, in some instances, this diffusion process also generates non-seismic motions that, in turn, influence the seismic activity, in particular when injection stops.
A generalized theory of acoustic emission (AE) is developed on the basis
of the theory of elastodynamics and dislocation models. Acoustic
emission sources are represented as dislocation sources and include both
discontinuities of displacement components and tractions. AE waves are
observed at a stress free surface. Therefore, Green's functions in a
half space are obtained as Lamb's solutions. FORTRAN programs for
computing these functions for non-Cauchy solids are developed. Several
Green's functions are calculated and simulated AE waveforms are
obtained. The applicability of the present theory and the relevancy of
these programs for theoretical and experimental research of AE are
discussed.
We have inverted polarity and amplitude information of representative microearthquakes to investigate source mechanisms of seismicity induced by hydraulic fracturing in the Carthage Cotton Valley, east Texas, gas field. With vertical arrays of four and eight three-component geophones in two monitoring wells, respectively, we were able to reliably determine source mechanisms of the strongest events with the best signal-to-noise ratio. Our analysis indicates predominantly non–double-couple source mechanisms with positive volumetric component consistent with opening cracks oriented close to expected hydraulic fracture orientation. Our observations suggest the induced events are directly the result of opening cracks by fluid injection, in contrast to many previous studies where the seismicity is interpreted to be primarily shearing caused by pore pressure diffusion into the surrounding rock or associated with shear stresses created at the hydraulic fracture tip.
Roughness is widely observed on natural fractures, and its impact on the potential for induced seismicity and associated fluid migration in the subsurface remains unclear. Here we perform fracture shearing and fluid flow experiments on artificially fabricated fractures with specified roughness to investigate the role of fracture roughness on frictional properties and permeability evolution. Given the experimental conditions, we observe that rough fractures show high roughness ratio Sq/Lw and return higher frictional strength due to the presence of cohesive interlocking asperities. Rough fracture surfaces show velocity strengthening behavior in the initial shearing stage, which may evolve to velocity neutral and velocity weakening at greater displacements—suggesting a dynamic weakening that rough fractures become less stable with shearing. The surface roughness exerts a dominant control on permeability evolution over the entire shearing history. Permeability declines monotonically by about 2 orders of magnitude for smooth fractures. For high roughness fractures, the permeabilities evolve episodically due to cycled compaction and dilation during shearing. With a slip distance of 6 to 8 mm, permeability of the rough surface may enhance up to an order of magnitude, but significant permeability reduction may also occur for rough samples when asperities are highly worn with gouge clogging flow paths. However, there is no obvious correlation between permeability evolution and frictional behavior for rough fracture samples when fractures are subject to sudden sliding velocity changes.
In this paper, we consider fractured sorbing media (e.g., gas shale and coal bed methane reservoirs) as either dual porosity media comprising matrix-fracture or as triple porosity media comprising separate organic and inorganic matrix components and fractures. We accommodate the combination of mechanical deformation and desorption induced matrix shrinking in conditioning the evolution of fracture aperture and effective stress difference between each medium. These considerations result in an improved permeability evolution model (IPEM) for both dual porosity and triple porosity fractured sorbing media. Then we have simplified the model for triple porosity fractured sorbing media by reducing the geometry configuration from three dimensional to one dimensional, marked as SIPEM1. Specifically, SIPEM1 is a model simplified from the IPEM, and consider that when the size of the REV and the volumetric strain is small, replacing the volume with the side length of each layer medium in defining the model will bring relatively small error. This model is further simplified to SIPEM1-1 by assuming that the effective stress of each medium is the same. Then we have validated the models with field data. Finally, we compared prediction results from these models under different conditions. This study has found that IPEM is the most accurate model, especially for fractured sorbing media with a larger compressibility. SIPEM1-1 does not consider the difference of the effective stress of each medium and thus it is relatively less accurate in describing the evolution of permeability compared with SIPEM1 that considers this difference. This gap increases with the increase of permeability difference between fracture and matrix.
Significance
Millions of Americans rely on self-supply groundwater wells for drinking water, but the number of these wells that are located near hydraulic fracturing operations is unknown. Here, we show that approximately half of all hydraulically fractured wells stimulated in 2014 exist within 2–3 km of one or more domestic (public and self-supply) groundwater wells. Our finding that many hydraulically fractured and domestic groundwater wells are colocated emphasizes that determining how frequently hydraulic fracturing activities impact groundwater quality is important to maintaining high-quality water in many domestic wells.
The use of fresh water as a fracturing fluid has limitations such as limited water availability in arid areas and negative impacts of water on oil and gas production in formations with high clay content. Alternatives to water for well fracturing include tailored energetic materials such as novel explosives. High energy gas fracturing (HEGF) creates radial fractures with fracture-orientations independent of formation stress anisotropy and heterogeneity. This eliminates the requirement of in-situ stress orientation for designing multi-hydraulic water-fracturing horizontal wells. Assuming uniformly distributed radial fractures around wellbore, an analytical well productivity model was derived in this study to predict productivity of HEGF-completed oil wells under pseudo steady state flow condition. Field case studies and sensitivity analyses were performed with the analytical model. Result of field case studies indicates that the analytical model over-predicts productivity of HEGF-completed wells by about 10%. Sensitivity analysis with the analytical model shows that the productivity of HEGF-completed wells reaches a maximum value at an optimal number of radial fractures around the wellbore. The productivity of the HEGF-completed wells increases non-linearly with fracture conductivity. But the benefit of increasing fracture conductivity levels out beyond fracture conductivity 2000 md-inch for the typical case investigated in this study.
Abstract Carbon dioxide (CO2) sequestration in deep shale reservoirs with enhanced shale gas methane (CH4) recovery contributes to both CH4 recovery and CO2 emission mitigation. In this work, the adsorption behaviors of pure CH4 and CO2 on shales, and the displacement behaviors of CH4 adsorbed on shales by CO2 injection were investigated. The single component adsorption indicates that the simplified Ono-Kondo lattice model can well describe both CH4 and CO2 adsorption on shales. The maximum adsorption capacity of CH4 obtained from the simplified Ono-Kondo lattice model shows significant linear correlation with the micropore parameters of shales, while this linear correlation is weak for CO2. The investigation on the displacement behaviors based on the improved experimental procedure and data processing method raised in this work confirms that CH4 adsorbed on shales can be displaced by CO2, which provides the experimental evidence for the feasibility of CO2 sequestration in shale reservoirs with enhanced CH4 recovery. The amounts of recovered CH4 and stored CO2 increase with CO2 injection pressure. The recovery yield of CH4 due to CO2 injection is higher for shales with smaller micropore parameters or lower adsorption performance. The microscopic mechanism of the displacement process is strongly related to the injection pressure of CO2. Based on the conceptual model established for the process of CH4 adsorbed on shales displaced by CO2 injection, it is recommended to inject CO2 after partial desorption of CH4, which can improve CH4 recovery and CO2 sequestration of the target shale reservoirs.
Permanently sequestering carbon dioxide (CO2) in gas-bearing shale formations is beneficial in that it can mitigate greenhouse gas emissions as well as enhance gas recovery in production wells. This is possible due to the sorption properties of the organic material within shales and their greater affinity for CO2 over methane (CH4). The phenomenon of preferentially adsorbing CO2 while desorbing CH4 has been proven in unconventional coalbed methane reservoirs successfully, and is feasible for shale formations. The objective of this paper is to explore the potential for enhanced gas recovery from gas-bearing shale formations through a successful small-scale ‘huff-and-puff’ injection of CO2 into a targeted shale formation. Approximately 510 short tons of CO2 were successfully injected into a horizontal production well completed in the Chattanooga Shale formation in Morgan County, Tennessee. After the injection phase, the well was shut-in to allow for the CO2 to equilibrate within the target formation. After the soaking phase was completed, the well was flowed back and returned to normal production. During this flowback phase, gas composition and flow rate were frequently monitored. Results indicated that there was a significant increase in gas flow rate during the first five months of the flowback phase. There was also a significant increase in gas quality, such that the percent composition of NGLs (natural gas liquids), including ethane, propane, and butane, increased. The results from this injection test confirm the injectivity and storage potential of CO2 in organic shales formations while enhancing gas recovery.
Supercritical carbon dioxide (SC-CO2) fracturing is a promising technology for developing shale gas because it can effectively solve problems related to shale swelling and lack of water resources. This work conducted simulation experiments on SC-CO2 fracturing in shale for the first time. Compared with hydraulic fracturing, using SC-CO2 as the fracturing fluid reduces the pressure needed to initiate fractures by more than 50%. This reduction is due to the increased percolation and pore pressure effects of using SC-CO2. Acoustic emission tests were used to monitor the progress of fracturing in shale and high-energy CT scanning documented fracture morphology. CT scanning shows that SC-CO2-induced fractures are irregular multiple cracks. These numerous crooked cracks are more likely to induce secondary fractures in shale and to connect with natural fracture and bedding to form complex fracture networks than those formed by hydraulic fracturing. The volume of rock fractured by SC-CO2 is several times that fractured by hydraulic fracturing and the surfaces of the fractures opened by SC-CO2 are more complex and rugged. SC-CO2 fracturing can achieve better fracture networks for reservoir stimulation in shale than in sandstone, and the degree of bedding development has a great influence on the complexity of the SC-CO2 induced fractures. Namely, using SC-CO2 as fracturing fluid can increase fracture conductivity and hence achieve increased shale gas production. This study also determined how fractures propagate under different horizontal stress regimes.
Many of the environmental impacts associated with hydraulic fracturing of unconventional gas wells are tied to the large volumes of water that such operations require. Efforts to develop non-aqueous alternatives have focused on carbon dioxide as a tunable working fluid even though the full environmental and production impacts of a switch away from water have yet to be quantified. Here we report on a life cycle analysis of using either water or CO2 for gas production in the Marcellus shale. The results show that CO2-based fluids, as currently conceived, could reduce greenhouse gas emissions by 400% (with sequestration credit) and water consumption by 80% when compared to conventional water-based fluids. These benefits are offset by a 44% increase in net energy use when compared to slickwater fracturing as well as logistical barriers resulting from the need to move and store large volumes of CO2. Scenario analyses explore the outlook for CO2, which under best-case conditions could eventually reduce life cycle energy, water, and GHG burdens associated with fracturing. To achieve these benefits, it will be necessary to reduce CO2 sourcing and transport burdens and to realize opportunities for improved energy recovery, averted water quality impacts, and carbon storage.
We conducted hydraulic fracturing (HF) experiments on 170 mm cubic granite specimens with a 20 mm diameter central hole to investigate how fluid viscosity affects HF process and crack properties. In experiments using supercritical carbon dioxide (SC-CO2), liquid carbon dioxide (L-CO2), water, and viscous oil with viscosity of 0.051–336.6 mPa · s, we compared the results for breakdown pressure, the distribution and fracturing mechanism of acoustic emission (AE), and the microstructure of induced cracks revealed by using an acrylic resin containing a fluorescent compound. Fracturing with low-viscosity fluid induced three-dimensionally sinuous cracks with many secondary branches, which seem to be desirable pathways for enhanced geothermal system (EGS), shale gas recovery and other processes.
Supercritical carbon dioxide (ScCO2)-based reservoir fracturing associated with CO2-enhanced shale gas recovery is a promising technology to reduce water utilization in shale gas production and has the potential for CO2 sequestration. In the current research, experiments were conducted to explore the effectiveness of ScCO2 fracturing and the permeability of fractured shale under in situ stress and pore pressure. Computerized tomography scanning (CT scan) was used to characterize the fracture morphology. The results indicate that ScCO2 fracturing can induce complex fractures with various branches, which benefits the reservoir stimulation. There is a negative power relationship between the effective stress and permeability. However, the permeability reduction with effective stress depends on the stress path. The permeability substantially decreases with increasing effective stress, which is caused by the increase of the confining pressure. Nevertheless, the permeability decreases slowly when the increase of effective stress results from a decrease of the pore pressure. In addition, CO2 adsorption induces shale matrix swelling, influences the mechanical properties of shale, which significantly decreases the permeability of the shale, and the effect of adsorption on shale permeability is related to the stress state.
This paper mainly discusses the industrialization progress, "sweet spot" evaluation criterion, E&P technologies, success experiences, challenges and prospects of China's shale gas. Based on the geologic and engineering parameters of the Fuling, Changning and Weiyuan shale gas fields in the Sichuan Basin, this paper points out that China's shale gas has its particularity. The discoveries of super-giant marine shale gas fields with high evolution degree (Ro=2.0%-3.5%) and ultrahigh pressure (pressure coefficient=1.3-2.1) in southern China is of important scientific significance and practical value to ancient marine shale gas exploration and development to China and even the world. It's proposed that shale gas "sweet spots" must be characterized by high gas content, excellent frackability and good economy etc. The key indicators to determine the shale gas enrichment interval and trajectory of horizontal wells include "four highs", that is high TOC (>3.0%), high porosity (>3.0%), high gas content (>3.0 m3/t) and high formation pressure (pressure coefficient>1.3), and "two well-developed" (well-developed beddings and well-developed micro-fractures). It's suggested that horizontal well laneway be designed in the middle of high pressure compartment between the Upper Ordovician Wufeng Formation and Lower Silurian Longmaxi Formation. The mode of forming "artificial shale gas reservoir" by "fracturing micro-reservoir group" is proposed and the mechanism of "closing-in after fracturing, limiting production through pressure control" is revealed. Several key technologies (such as three-dimensional seismic survey and micro-seismic monitoring of fracturing, horizontal wells, "factory-like" production mode, etc.) were formed. Some successful experiences (such as "sweet spot" selection, horizontal well laneway control, horizontal length optimization and "factory-like" production mode, etc.) were obtained. The four main challenges to realize large-scale production of shale gas in China include uncertainty of shale gas resources, breakthroughs in key technologies and equipment of shale gas exploration and development below 3 500 m, lower cost of production, as well as water resources and environment protection. It is predicted that the recoverable resources of the Lower Paleozoic marine shale gas in southern China are approximately 8.8×1012 m3, among which the recoverable resources in the Sichuan Basin are 4.5×1012 m3 in the favorable area of 4.0×104 km2. The productivity of (200-300)×108 m3/a is predicted to be realized by 2020 when the integrated revolution of "theory, technology, production and cost" is realized in Chinese shale gas exploration and development. It is expected in the future to be built "Southwest Daqing Oilfield (Gas Daqing)" in Sichuan Basin with conventional and unconventional natural gas production.
An extended overview of the history of the fracturing technology is presented. Fracturing can be traced to the 1860s, when liquid nitroglycerin (NG) was used to stimulate shallow, hard rock wells in Pennsylvania, New York, Kentucky, and West Virginia. In the 1930s, the idea of injecting a nonexplosive fluid (acid) into the ground to stimulate a well began to be tried. But when Floyd Farris of Stanolind Oil and Gas Corporation (Amoco) performed an in-depth study to establish a relationship between observed well performance and treatment pressures that formation breakdown during acidizing, water injection, and squeeze cementing became better understood. The first fracturing treatment used screened river sand as a proppant. Conventional cement- and acid-pumping equipment was used initially to execute fracturing treatments. Development of equipment including intensifiers, slinger, and special manifolds continues for hydraulic fracturing.
Hydraulic Fracturing
Editor’s note: In 2006, SPE honored nine pioneers of the hydraulic fracturing industry as Legends of Hydraulic Fracturing. Claude E. Cooke Jr., Francis E. Dollarhide, Jacques L. Elbel, C. Robert Fast, Robert R. Hannah, Larry J. Harrington, Thomas K. Perkins, Mike Prats, and H.K. van Poollen were recognized as instrumental in developing new technologies and contributing to the advancement of the field through their roles as researchers, consultants, instructors, and authors of ground-breaking journal articles.
Following is an excerpt from SPE’s new Legends of Hydraulic Fracturing CDROM, which contains an extended overview of the history of the technology, list of more than 150 technical papers published by these industry legends, personal reflections from a number of the Legends and their colleagues, and historic photographs. For more information on the CDROM, please go to http://store.spe.org/Legendsof-Hydraulic-Fracturing-P433.aspx.
Since Stanolind Oil introduced hydraulic fracturing in 1949, close to 2.5 million fracture treatments have been performed worldwide. Some believe that approximately 60% of all wells drilled today are fractured. Fracture stimulation not only increases the production rate, but it is credited with adding to reserves—9 billion bbl of oil and more than 700 Tscf of gas added since 1949 to US reserves alone—which otherwise would have been uneconomical to develop. In addition, through accelerating production, net present value of reserves has increased.
Fracturing can be traced to the 1860s, when liquid (and later, solidified) nitroglycerin (NG) was used to stimulate shallow, hard rock wells in Pennsylvania, New York, Kentucky, and West Virginia. Although extremely hazardous, and often used illegally, NG was spectacularly successful for oil well “shooting.” The object of shooting a well was to break up, or rubblize, the oil-bearing formation to increase both initial flow and ultimate recovery of oil. This same fracturing principle was soon applied with equal effectiveness to water and gas wells.
In the 1930s, the idea of injecting a nonexplosive fluid (acid) into the ground to stimulate a well began to be tried. The “pressure parting” phenomenon was recognized in well-acidizing operations as a means of creating a fracture that would not close completely because of acid etching. This would leave a flow channel to the well and enhance productivity. The phenomenon was confirmed in the field, not only with acid treatments, but also during water injection and squeeze-cementing operations.
Organic shales are exposed to treatment fluids during and after hydraulic fracturing operations. The fluid–shale interaction influences the petrophysical alteration of the fractured shale and the fate of the fracturing fluid. We systematically measured the spontaneous water and oil intake of five shale samples collected from the cores of two wells drilled in the Horn River basin. The samples represent three shale formations with different mineralogy and petrophysical properties. We characterize the samples by measuring the porosity, conducting X-ray diffraction, and interpreting the well logging data and scanning electron microscopy images. The water intake is higher than the oil intake for all samples. The excess water intake and the physical alteration degree correlate with the shale mineralogy and petrophysical properties. The ratio between the water and oil intake is much higher than the ratio between the water and oil capillary pressures, even for the non-swelling shales. The comparative study indicates that the water intake of organic shales is controlled by both adsorption and capillarity.
Carbon dioxide (CO2) is often used for enhanced oil recovery
in depleted petroleum reservoirs, and its behavior in rock is also of
interest in CO2 capture and storage projects. CO2
usually becomes supercritical (SC-CO2) at depths greater than
1,000 m, while it is liquid (L-CO2) at low temperatures. The
viscosity of L-CO2 is one order lower than that of normal
liquid water, and that of SC-CO2 is much lower still. To
clarify fracture behavior induced with injection of the low viscosity
fluids, we conducted hydraulic fracturing experiments using 17 cm cubic
granite blocks. The AE sources with the SC- and L-CO2
injections tend to distribute in a larger area than those with water
injection, and furthermore, SC-CO2 tended to generate cracks
extending more three dimensionally rather than along a flat plane than
L-CO2. It was also found that the breakdown pressures for SC-
and L-CO2 injections are expected to be considerably lower than for
water.
Supercritical CO2 (SC-CO2) fluid has the properties of low viscosity and high diffusion capacity near gas and higher density near liquid, so it showed great vitality at the beginning of its use in drilling technology at the end of the last century. This article analyzes the thermophysical properties of SC-CO2 fluid, and the properties of shale gas and reservoir are analyzed at different aspects of drilling and reservoir formation, while the characteristics of shale gas development are summarized also. Combining the characteristics of SC-CO2 fluid and shale gas reservoir exploitation, the feasibility of shale gas exploitation with SC-CO2 is demonstrated in detail. Meanwhile, the technical and economic superiorities of it are also analyzed. It is believed that the shale gas exploitation with SC-CO2 will achieve great success in economic and technical aspects, and it will provide much more clean energy and make a great contribution to protecting the environment.
Cubical granite specimens were fractured by borehole pressurisation of 1 cP water, 80 cP oil and via a urethane sleeve. Viscous oil tends to generate thick and planar cracks with few branches, while water tends to generate thin and wavelike cracks with many secondary branches. While penetrating fluids extended cracks rapidly, pressurization via a urethane sleeve led to stepwise crack extension. Fault-plane solutions of AE (Acoustic Emission) events indicated that shear-type mechanisms were dominant during water injection and sleeve pressurization, whereas tensile-type mechanisms were dominant during oil injection. These results could be helpful in optimizing stimulation treatments in the petroleum industry.
An application of a moment tensor analysis to acoustic emission (AE) is studied to elucidate crack types and orientations of AE sources. A moment tensor inversion based on P wave amplitude is employed to determine six independent tensor components. Selecting only P wave portion from the full-space Green's function of homogeneous and isotropic material, a computer code named SiGMA (simplified Green's functions for the moment tensor analysis) is developed for the AE inversion analysis. To classify crack type and to determine crack orientation from moment tensor components, a unified decomposition of eigenvalues into a double-couple (DC) part, a compensated linear vector dipole (CLVD) part, and an isotropic part is proposed. The results suggest that tensile cracks are generated first at weak seams and then shear cracks follow on the opened joints. -from Author
Explosive loading in borehole configurations has been investigated to assess the relative importance of internal gas pressurization and stress-wave-induced circumferential tensions for extending radial cracks originating at the borehole walls. Simple calculations of an extending crack (with and without confining pressure) were performed to estimate an upper bound on crack length resulting solely from internal pressurization for comparison with the crack length resulting solely from tensile stresses. These calculations indicated that a internal gas pressure could increase the crack length by a factor of 10 to 100 (no confining pressure) or 3 to 25 [6.9-MPa (1000-psi) confining pressure] compared with the tensile stresses acting alone. Simple laboratory experiments were performed using 3.2 × 10−3m diameter (1/8in.) by 1.52 × 10−1m long (6 in.) borehole charges centered in a 1.3 × 10−2m diameter (1/2in.) borehole in transparent Plexiglas cylinders 3 × 10−1m in diameter by 3 × 10−1m long (12in. by 12in.) to verify these computational results. Two tests were performed: one with a thin (5.08 × 10−4m) steel liner to contain the explosive gases and one without a liner so that the explosive gases could enter and pressurize the fractures. A confining pressure of 6.9 MPa (1000 psi) was applied to the Plexiglas cylinders in both experiments to better simulate field conditions and to contain the cracks within the cylinder; all other experimental conditions were identical. These experiments indicated that the primary effect of the explosive gases was to increase crack length by a factor of five to ten compared with the tensile stresses acting alone, in approximate agreement with the predictions.
The technologies and practices that have enabled the recent boom in shale gas production have also brought attention to the environmental impacts of its use. It has been debated whether the fugitive methane emissions during natural gas production and transmission outweigh the lower carbon dioxide emissions during combustion when compared to coal and petroleum. Using the current state of knowledge of methane emissions from shale gas, conventional natural gas, coal, and petroleum, we estimated up-to-date life-cycle greenhouse gas emissions. In addition, we developed distribution functions for key parameters in each pathway to examine uncertainty and identify data gaps such as methane emissions from shale gas well completions and conventional natural gas liquid unloadings that need to be further addressed. Our base case results show that shale gas life-cycle emissions are 6% lower than conventional natural gas, 23% lower than gasoline, and 33% lower than coal. However, the range in values for shale and conventional gas overlap, so there is a statistical uncertainty whether shale gas emissions are indeed lower than conventional gas. Moreover, this life-cycle analysis, among other work in this area, provides insight on critical stages that the natural gas industry and government agencies can work together on to reduce the greenhouse gas footprint of natural gas.
Unconventional fracturing fluids for tight gas reservoirs SPE Hydraulic Fracturing Technology Conference (SPE)
- D V S Gupta
Gupta, D.V.S. (2009). Unconventional fracturing
fluids for tight gas reservoirs SPE Hydraulic
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The rheological behavior of energized fluids and foams with application to hydraulic fracturing
- S A Faroughi
- A J Pruvot
- .-C J Mcandrew
Faroughi, S.A., Pruvot, A.J.-C.J., and
McAndrew, J. (2018). The rheological behavior
of energized fluids and foams with application
to hydraulic fracturing. J. Petrol. Sci. Eng.
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Supercritical carbon dioxide fracturing in shale and the coupled effects on the permeability of fractured shale: an experimental study
- J Zhou
- G Liu
- Y Jiang
- X Xian
- Q Liu
- D Zhang
- J Tan
Zhou, J., Liu, G., Jiang, Y., Xian, X., Liu, Q.,
Zhang, D., and Tan, J. (2016). Supercritical
carbon dioxide fracturing in shale and the
coupled effects on the permeability of
fractured shale: an experimental study. J. Nat.
Gas Sci. Eng. 36, 369-377.
- T Ishida
- Y Chen
- Z Bennour
- H Yamashita
- S Inui
- Y Nagaya
- M Naoi
- Q Chen
Ishida, T., Chen, Y., Bennour, Z., Yamashita, H.,
Inui, S., Nagaya, Y., Naoi, M., Chen, Q.,
Joule 3, 1-14, August 21, 2019
The rheological behavior of energized fluids and foams with application to hydraulic fracturing
- Faroughi
Shale gas in China: characteristics, challenges and prospects (II)
- Zou