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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 this regard, waterless fluid technologies (Isaka et al. 2019;Song et al. 2019), including propellants and fluids such as CO 2 , and N 2 , have been explored at small scales and in shallow reservoirs. The high-pressure pulses generated by propellants can initiate fractures though concerns remain about their ability to propagate fractures beyond the near-wellbore region and their safe deployment. ...
... and the second one is called Haimson-Fairhurst (H-F) criterion: (Detournay and Carbonell 1997) have shown that the two criteria can be united into one in the context of poroelasticity, with the H-W criterion being used for rapid pressurizations and low permeability formations, and the H-F criterion being used for slow pressurizations and high permeability formations. All else being equal, the case of slower pressurization and higher permeability is expected to lead to lower breakdown pressures, which is consistent with the results in (Song et al. 2019;Lu et al. 2020). Note that the experimental result shown below are not for longitudinal fractures, and hence these two criteria are not directly applicable, but the same general trends would be expected since the underlying physics are how stress changes with pore pressure diffusion and are not specific to the wellbore geometry. ...
... For the injection strategy consisting of injecting water in HDR, the conductivity is generally less than 2µm 3 (radial flow) even when fracturing at very high flow rates (25 mL/ min). These findings are consistent with other results published in the literature, for both shale and granite at room temperature (Song et al. 2019). 2 The pressurization rate does not significantly affect fracture conductivity when fracturing with water but is a key factor for generating fractures with high conductivity in CO 2 -based fluids. ...
The objective of this work is to study the performance of 1wt% StimuFrac fluid [polyallylamine (PAA) in water] in ½-foot size rock samples under thermal and fluid phase conditions representative of enhanced geothermal systems (EGS) and reveal the mechanisms governing the fracturing process. Four fracturing fluids including water, CO2, CO2 with water, and CO2 with aqueous PAA were used.
For all the water “only” fracturing tests, the conductivity of the rock fractured is quite low (less than 2 μm3 based on radial flow assumption), regardless of the constant flow rate or discrete pressure increments injection approach. For all three CO2-based fracturing fluids, granite was fractured at higher breakdown pressures, higher transient flow rates, and generated higher-conductivity fractures as compared to water. When partially saturating the rock sample with 1wt% PAA aqueous solution followed by fracturing with CO2, the volume expansion and viscosity increase triggered by CO2-induced cross-linking PAA leads to a faster pressure increase than CO2 in water saturated or initially dry. This faster pressurization rate is caused by a decrease in relative permeability of CO2 in the presence of the high-viscosity cross-linked fluid compared to the un-crosslinked CO2/water.
It was also found that CO2 as a fracturing fluid can generate high fracture conductivity only when injected at very high flow rates in the presence of water or in hot dry rock (HDR). However, the conductivity of CO2 fracturing in HDR is highly variable. CO2 injected in the presence of 1wt% aqueous PAA generates fractures with the highest conductivity independently of injection flow rates and using 1/6 of the mass of CO2 as compared to CO2 fracturing in HDR.
The results of this study suggest CO2/PAA is the best performing stimulation fluid under the studied P/T conditions. CO2/PAA offers the following three additional advantages over waterless CO2, and CO2/water fracturing fluids: i) it requires significantly lower volumes of CO2 due to the reduced leak off; ii) large fractures can be generated reproducibly at both low and high CO2 injection flow rate, and iii) the reversible (previously reported) viscosity increase could be beneficial to transport proppants when they become available for EGS.
... As a result, the cement and steel bracing that is used to isolate the drilled well from underwater aquifers is less likely to break. Therefore, the risk of oil and gas leaks, especially at critical parts, is reduced (Song et al., 2019). ...
... Whereas this would lead to a cheaper fracking fluid resource in comparison with water, as related technologies are developing rapidly. At the same time, the use of it during the fracking process could fully compensate for the collection costs of carbon dioxide (Song et al., 2019). This innovation might be a promising solution to save underwater and surface water from contamination as well as to deplete the amount of wastewater and reduce stress on water demand. ...
Global economic forces underpin political and social issues and have real impacts on the quality of life in local communities, cities, states and regions. In the face of potential volatility, leaders in every ‘place’ concern themselves with how they can ensure local economic resiliency for present and future generations. This book argues for the strategic management of places through intentional public policy that brings together stakeholders from the public, private and nonprofit sectors to create an inclusive and sustainable economic path forward. While many economists and political scientists have proposed one-size-fits-all approaches, this book puts forward a more holistic approach, giving local leaders and policymakers the tools to take inventory of their local contexts and providing case study examples of how to craft public policies that create prosperous and sustainable economic conditions.
... Therefore, the risk of oil and gas leaks, especially at critical parts, is reduced. (Song et al., 2019) Carbon dioxide is not only used, parts of it are also stored simultaneously in the new created fracture formations. Therefore, it is enabling the whole process to become much greener. ...
... At the same time, the use of it during the fracking process could fully compensate the collection costs of carbon dioxide. (Song et al., 2019) This innovation might be a promising solution to safe underwater and surface water from contamination as well as to deplete the amount of wastewater and stress on water demand. It would also make fracking more competitive for the gas and oil companies. ...
From a country-wide perspective, the state of Texas contributes the second-highest amount to the GDP of the United States). Within Texas, the energy sector has emerged as one of the strongest and most promising factors for economic development. The invention of fracking gave the oil and gas industry advanced possibilities to reach resources in places where traditional methods had to surrender. This technique enabled the state of Texas to become the country’s most important oil and gas provider. However, fracking is claimed to cause various negative side effects, especially on nature and the environment. This may bring up plenty of challenges for communities, companies, and policymakers. This paper uses the framework from “Everything in its Place: Entrepreneurship and the Strategic Management of Cities, Regions, and States” by David B. Audretsch to analyze Texas and the impacts fracking has on the economy. Solutions to rectify the situation are presented. These include implementations for water usage, regulations for chemicals used in the process, and the strengthening of entrepreneurial activities at universities.KeywordsFracking, EnergyEnvironment and GrowthHealthTexas
... These characteristics of shale fractures are consistent with findings reported by Jia et al. (2018). Additionally, the main fracture generated by water injection terminated when encountering natural fractures, similar to observations described by Song et al. (2019). That is, fracture initiation and propagation induced by water and SC-CO 2 fracturing were influenced by the bedding or weak surface in the specimens; however, SC-CO 2 fracturing generated more fractures with greater bifurcation and higher tortuosity. ...
... That is, fracture initiation and propagation induced by water and SC-CO 2 fracturing were influenced by the bedding or weak surface in the specimens; however, SC-CO 2 fracturing generated more fractures with greater bifurcation and higher tortuosity. Concerning the fracturing mechanism for the various fracturing fluids (water, CO 2 , N 2 , and others), there are many explanations from different scales (Ranjith and Zhang, 2019;Song et al., 2019). For instance, fluid with low viscosity is expected to provide a strong seepage effect in the matrix with small capillary blockage and low viscous force (Liu et al., 2020). ...
Supercritical CO2 (SC–CO2) would be a potential substitute for water-based fracturing fluid widely used in the present hydraulic fracturing of shale reservoirs. However, the field application of SC-CO2 fracturing is still in its infancy. Laboratory experiments are crucial for understanding the effects of various fracturing parameters and validating numerical simulations before conducting costly field trials. This paper first introduces the design of a self-developed experimental apparatus for fracturing cylindrical rock specimens and outlines the working principles of six functional modules. The entire experimental system is flexible because its functional modules can be used interchangeably. Subsequently, some key designs are emphasized. (1) A packer with the sealing of O and Y rings exhibits a good seal efficiency for a relatively small wellbore; moreover, this packer can be conveniently moved out from the fractured shale without damaging the specimen. (2) Downhole temperature measurement structure integrated into the packer can sensitively monitor the CO2 temperature variation at a high sampling rate during the entire SC-CO2 fracturing process. (3) The design of the triaxial core holder contributes to the realization of withstanding high axial-confining and fluid injection pressures and customized installation of acoustic emission (AE) sensors. Ultimately, some fracturing experiments with water and SC-CO2 as fracturing fluids and seepage tests with nitrogen (N2) under various test parameters are successfully conducted. The results indicate that, after the specimen fractures, the injection pressure would be decreased to the confining pressure due to the confining chamber sealing design; there is a simultaneous sharp variation in the temperature at the bottom of the wellbore. SC-CO2 fracturing generates more fractures with greater bifurcation and higher tortuosity. The gas flow rate decreases with increasing confining pressure, whereas it increases significantly with increasing injection pressure. In general, these experimental results can validate the performance and feasibility of the self-developed experimental apparatus.
... 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 fracturing enables offsetting of carbon emissions from the development process of oil and gas resources, which may even open a new horizon for the oil and gas industry that struggling with carbon emission reduction difficulties under China's carbon neutrality policy. In addition to environmental benefits, CO 2 fracturing does not damage a stimulated reservoir and exhibits competitive adsorption capacity for effective extraction of oil and natural gas (Song et al., 2019;Mojid et al., 2021;Hazarika and Boruah, 2022). The theoretical adsorption capacity of CO 2 in shales and coal seams is higher than that of CH 4 , so CH 4 in adsorbed gas can be displaced by competitive adsorption to improve oil and gas production from a single well (Kang et al., 2011;Huo et al., 2017;Zhang et al., 2023). ...
Shale oil resources are abundant in China, and their large-scale development plays a critical role in the national energy strategy. Hydraulic fracturing is widely employed for shale oil extraction, but the large-scale water consumption in this process poses serious environmental concerns. In recent years, CO2 fracturing has been proposed as an alternative method to improve fracturing effectiveness, reduce water consumption, and simultaneously store CO2 underground. This is the first field-testing study in China to systematically analyze the CO2 fracturing technology and quantitatively evaluate its recovery efficiency and CO2 storage capacity in the shale oil wells in Jianghan Basin. We designed and conducted a comparative investigation of hydraulic fracturing, CO2-water fracturing, and CO2 methanol-based fracturing techniques in terms of the effectiveness of fracturing, water saving, and CO2 storage. The results showed that CO2 methanol-based fracturing was most effective in eliminating the need for freshwater consumption on site and storing CO2, with an effective CO2 storage rate as high as 82.5%, suggesting a promising direction for carbon offset in the oil and gas industry. CO2-water fracturing reduced freshwater consumption and also effectively stored CO2 at an effective storage rate of up to 79.5%, making it more efficient than hydraulic fracturing but less so than CO2 methanol-based fracturing. The research provides a valuable reference for the development and practice of waterless fracturing for shale resources, and also sheds light on the potential of carbon storage in the oil and gas industry to achieve the carbon neutrality goal of China.
... After analyzing a number of publications [155][156][157], the authors came to the conclusion that today only, less than 5% of the world's oil production is accounted for by projects to increase oil recovery by tertiary methods. At the same time, EOR is one of the methods of oil production that increases the productivity of oil wells. ...
In world practice, the role of reproduction of raw material base of oil production by implementing modern methods of oil recovery enhancement (thermal, gas, chemical, microbiological) on the basis of innovative techniques and technologies is rapidly growing and is becoming more important. It is concluded that at present, the priority of increasing oil reserves in world oil production is the development and industrial introduction of modern integrated methods of enhanced oil recovery, which can provide a synergistic effect in the development of new and developed oil fields. This article presents a review and comparative analysis of theoretical and practical methods of improving oil recovery of conventional and unconventional reservoirs. The paper examines in detail methods of improving oil recovery, taking into account the factors of enhanced oil recovery of oil reservoirs. Considered the main methods and technologies currently used to develop oil fields and recommendations for their effective use, taking into account the variety of external factors of oil production: the geological structure of the reservoir, its volume, and properties of oils. It is shown that there is no universal method of oil reservoir development, and it must be chosen after a thorough feasibility study among several proposed models. When describing the methods of enhanced oil recovery, special attention is also paid to the physical processes that occur as a result of applying the technology. In conclusion, the positive and negative characteristics of the presented methods included in EOR are presented, and recommendations that may influence the choice of practical solutions for engineers and oil producers are given. Conclusions are made that development systems, placement and choice of operating mode of wells essentially depend on the geological structure of the reservoir, its volume and properties of oils. An important role in this is the construction of a geological model of the production facility. The used hydrodynamic models of development are based on physical laws, about which oil producers sometimes don’t even suspect, and the authors of the models are not always able to convey it to the real producers. The authors consider it reasonable to make a logical generalizing conclusion that understanding processes occurring in the reservoir and taking appropriate measures for optimization and intensification of oil production will allow making oil production as effective as possible.
... Furthermore, methane, the fundamental part of coalbed methane, is a major source of severe environmental pollution [5,6]. The annihilation effect of methane on the ozone layer and its greenhouse impact are seven times and twenty-one times higher than those of carbon dioxide (CO 2 ), respectively [7,8]. However, CBM can be utilized as a spotless, productive, and environment-friendly wellspring of energy. ...
Carbon dioxide (CO2) is both a primary greenhouse gas and a readily available energy source. In this study, a new underground coal permeability enhancement technique utilizing cryogenic liquid CO2 (L-CO2) cyclic injection is proposed. The key parameters that determine the feasibility of this technique are cycle period and cycle number within a fixed working period. The optimal value of these two parameters mainly depends on the pore structure evolution law of coal cores before and after cryogenic L-CO2 cyclic freeze–thaw. Accordingly, nuclear magnetic resonance (NMR) was employed to study the evolution characteristics of the fracture networks and pore structures in coal cores subjected to different freeze–thaw cyclic modes. The results demonstrated that the amplitude and width of all peaks of the T2 spectra of the three coal cores (lignite, gas coal, and 1/3 coking coal) increased with an increase in the number of injection cycles. Additionally, as the number of freeze–thaw cycles (Nc) increased, the total porosity and effective porosity of the coal cores increased linearly before stabilizing, while the residual porosity first steadily diminished and afterwards became constant. Furthermore, the variation in the total porosity and residual porosity of the coal cores continuously diminished with an increase in the level of metamorphism. The NMR permeability of the coal cores showed a similar pattern to the porosity. Accordingly, the optimal parameters for cryogenic L-CO2 cyclic injection during a complete working time were determined to be Nc = 4 and Pc = 30 min. A field test demonstrated that after L-CO2 cyclic freeze–thaw treatment, the average gas drainage concentration of a single borehole in the test region increased by 1.93 times, while the pure flow of a single gas drainage borehole increased by 2.21 times. Finally, the gas attenuation coefficient decreased from 0.036 to 0.012. We concluded that the proposed permeability enhancement technique transformed coal seams from hard-to-drain to drainable.
... The fracture propagation laws of SC-CO 2 fracturing are more complicated in unconventional reservoirs due to the adsorption of SC-CO 2 on the rock surface and the existence of weak planes, such as natural fractures and bedding planes (BPs). Artificial fractures in SC-CO 2 fracturing can penetrate natural fractures and propagate in the matrix (Song et al., 2019). Besides, they can also merge with natural fractures (Fang et al., 2014;Zhao et al., 2021), thus easily forming a larger stimulated reservoir volume (SRV). ...
As an emerging waterless fracturing technology, supercritical carbon dioxide (SC-CO2) fracturing can reduce reservoir damage and dependence on water resources, and can also promote the reservoir stimulation and geological storage of carbon dioxide (CO2). It is vital to figure out the laws in SC-CO2 fracturing for the large-scale field implementation of this technology. This paper reviews the numerical simulations of wellbore flow and heat transfer, fracture initiation and propagation, and proppant transport in SC-CO2 fracturing, including the numerical approaches and the obtained findings. It shows that the variations of wellbore temperature and pressure are complex and strongly transient. The wellhead pressure can be reduced by tubing and annulus co-injection or adding drag reducers into the fracturing fluid. Increasing the temperature of CO2 with wellhead heating can promote CO2 to reach the well bottom in the supercritical state. Compared with hydraulic fracturing, SC-CO2 fracturing has a lower fracture initiation pressure and can form a more complex fracture network, but the fracture width is narrower. The technology of SC-CO2 fracturing followed by thickened SC-CO2 fracturing, which combines with high injection rates and ultra-light proppants, can improve the placement effect of proppants while improving the complexity and width of fractures. The follow-up research is required to get a deeper insight into the SC-CO2 fracturing mechanisms and develop cost-effective drag reducers, thickeners, and ultra-light proppants. This paper can guide further research and promote the field application of SC-CO2 fracturing technology.
... Thus, CO 2 thickening technology by eliminating the undesired CO 2 mobility, can be developed to emerge as an alternative to WAG operations. The thickening technology employs dissolution of compounds i.e. 'Viscosifiers' such as polymer or small chain or surfactants with CO 2 creating a thermodynamically stable, transparent phase of high pressurized CO 2 with augmented viscous behavior [171]. Viscosifiers molecules by dispersing themselves throughout in CO 2 phase form network structures, thereby enhance CO 2 viscosity without losing the intrinsic nature of fluid. ...
Capturing carbon dioxide (CO2) at its combustion point and thereby storing it in geological sites or its usage for enhancing oil recovery (EOR) through miscible gas flooding technology aims to mitigate atmospheric/anthropogenic CO2 emissions. Injection of CO2 possesses an immense potential for production improvement in matured oil reservoirs. Oil recovery is increased by viscous fluid drive, oil phase swelling and oil viscosity reduction. Miscible CO2 floods diminish interfacial tension (IFT ∼ 0) between gas and oil, and alters the wettability. This review discusses the various technical aspects of oil production enhancement via miscible CO2 application with identification of the significant research gaps. The mechanisms of first contact and multiple contact miscibility, techniques of minimum miscibility pressure (MMP) determination (experimental, theoretical and numerical), the influence of CO2 concentration on rock mineralogy and surface roughness with various associated reservoir parametric (pressure, temperature, salinity, etc.), and the mechanisms of oil displacement from laboratory experiments to field applications are discussed elaborately. The review also deals with the new approaches of CO2 flooding viz. carbonated water injection, near miscible CO2 flooding, water alternating gas (WAG) injection, CO2 huff ‘n’ puff, and CO2 thickening. Finally, CO2-EOR in carbon capture, utilization and storage (CCUS), the environmental aspects, challenges and future outlooks of CO2 miscible flooding are discussed. Therefore, a repository of CO2 miscible EOR is established in this review assisting an enrichment in our current understanding of this topic.
... Zhang et al. (2019) and Cai et al. (2020) both discussed the anisotropic effects of shale on fracturing. In the aspect of fracture morphology analysis, an optical scanner was used to reconstruct the rough fracture surface at the macroscale (Song et al., 2019;Yang et al., 2022), while scanning electron microscopy (SEM) was applied to observe hydraulic fractures at the local microscale (He et al., 2020). Computed tomography (CT) scanning is another powerful tool for 3-D hydraulic fracture characterization (Guo et al., 2014;Zhang et al., 2017;Li et al., 2019). ...
Hydraulic fracturing is widely implemented in the exploration of marine shale gas. Affected by various geological and engineering factors, gas production after stimulation is not always satisfactory. To reveal the influential effect of multiple factors, laboratory hydraulic fracturing experiments are performed on Longmaxi marine shales by considering key parameters (deviatoric stress, confining pressure, pumping rate, fracturing fluid type, and bedding angle). The variation of breakdown pressures and the characteristics of hydraulic fractures are recorded and analyzed. The results show that the breakdown pressure increases with increasing deviatoric stress, confining pressure, pumping rate, and viscosity of the fracturing fluid. As the bedding angle varies from 0° to 90°, the breakdown pressure declines first and increases again. Furthermore, parameter sensitivity analysis indicates that geological factors (confining pressure, bedding angle, and deviatoric stress) would largely determine the breakdown pressure, while engineering factors (pumping rate, fracturing fluid type) could only affect it to a lesser extent. Computed tomography measurements show that natural fractures, originating from tectonic shear failure, could possess greater width than tension-dominated hydraulic and bedding fractures. Statistical analysis shows that the length of the hydraulic fractures alone is only approximately 150 mm. However, the fully activated natural and/or bedding fractures could help substantially increase the total fracture length to 600 mm. Low deviatoric stress, low confining pressure, low viscous slick-water, and high bedding angle are conducive to activating natural and bedding fractures and forming a complex fracture network. The aforementioned findings are valuable for the optimal design of field hydraulic fracturing.
... Carbon dioxide could replace water as the hydraulic fracturing fluid in shale reservoirs (Gandossi and Von Estorff, 2013;Middleton et al., 2015). CO 2 -fracturing has not yet been implemented as an industry practice, but it has the potential to address: (i) the scarcity of water in dry regions where most shale reservoirs are located and (ii) more economic approaches of storing CO 2 underground (Song et al., 2019). Employing CO 2 as the hydraulic fracturing fluid entails technical differences as compared to water. ...
We conducted a suite of experiments to evaluate the long-term permeability evolution of shale rocks under constant effective stress, before, during, and after interaction with supercritical carbon dioxide (scCO2). To do so, we measured the time-dependent evolution of argon permeabilities for the pre- and post-reacted samples (i.e., before and after long-term interaction with scCO2). In addition, we obtained permeability evolution during long-term interaction with scCO2. The samples showed either relatively constant permeabilities or a moderate decrease during pre-reaction long-term argon tests. The permeability evolution during long-term CO2 tests showed continuous increase, continuous decrease, or cycles of increase/decrease in permeability. The long-term response of the samples to CO2 included phenomena such as (i) salt precipitation, (ii) swelling-induced cracks, and (iii) carbonate dissolution. While it is obvious that salt precipitation and swelling-induced cracks decrease and increase the permeability, respectively, the sample response to carbonate dissolution proved to be more complex and may increase or decrease the permeability. The permeability evolution during post-reaction long-term argon injection is also affected by the contribution of each of these three phenomena, during long-term interaction with CO2. We observe increase, decrease, and constant permeability evolution during post-reaction argon tests. Our experiments reveal that the initial permeability of the samples plays a significant role on the long-term permeability response of shales in the presence argon and scCO2 fluids. This study shows that when shales are hydraulically fractured with CO2 their initial permeability has a more significant role than their permeability evolution over time.
... Up until now, more than 45% of natural gas production depends on foreign export . However, China is rich in unconventional gas reserves, especially the shale gas reserves (Song et al., 2019). In recent years, shale gas has become a new hot spot in global oil and gas exploration (Zhiltsov and Zonn, 2016). ...
In the process of shale gas development, different drilling, hydro-fracturing, and pumping speeds will produce different productivity effects. This reflects the effect of the loading rate of rock mechanics. Therefore, it is of great scientific significance to study the deformation and failure characteristics of shale under different loading rates. In order to reveal the loading rate effect of the Longmaxi shale, a series of laboratory experiments were carried out, including scanning electron microscope, XRD, and uniaxial compression tests at different loading rates. The results show that 1) the peak strength and elastic modulus of shale increase with the increase in the loading rate, but Poisson’s ratio has no obvious rule with the increase in the loading rate. In contrast, the loading rate causes the peak strength to vary by about 20%, which is larger than that of the elastic modulus. 2) The loading rate has a significant influence on shale failure. A higher loading rate will lead to severe damage but with simple cracks, whereas a lower loading rate will lead to complex damage of cracks. With the decrease in the strain rate, the length of the failure crack increases greatly. Therefore, a lower strain rate is helpful to form more broken fragments in the shale matrix. 3) By analyzing the relationship between elastic strain energy/dissipated energy and the loading rate, it is found that the elastic strain rate has a preliminary increasing and then a decreasing trend with the loading rate, but the dissipated energy has a decreasing trend with the loading rate. A higher loading rate is helpful to increase the brittleness of the shale, but a lower loading rate is beneficial to forming more cracks and a greater degree of fracture in the shale matrix. The effect of the loading rate on the mechanical properties and fracture properties of the shale is discussed. It is suggested that the lower hydro-fracturing rate is useful for generating more complex crack networks in the shale reservoirs.
... Shale formations have emerged as a promising option for CO 2 storage due to their wide availability, favourable pore structure and mineralogy (Fatah et al., 2020;Kang et al., 2011;Merey and Sinayuc, 2016;Liu et al., 2016;Zhou et al., 2019;Zhan et al., 2017). Previous studies reported that injection/migration of CO 2 into shale gas formations can enhance gas recovery (Zhan et al., 2017;Nuttall et al., 2005;Middleton et al., 2015;Lyu et al., 2018;Godec et al., 2013), minimize formation damage (Song et al., 2018), increase pore conductivity (Wang et al., 2019;Song et al., 2019) and even improve seal integrity (Hadian and Rezaee, 2019;Rezaee et al., 2017). However, the geochemical interactions between CO 2 and shales have not been totally understood given its impact on CO 2 dissolution, pH reduction, and minerals dissolution/precipitation Ilgen et al., 2018;Fatah et al., 2021a). ...
The research on Carbon Capture and Storage (CCS) has become fruitful as energy-intensive industries are working towards transitioning to low carbon energy industry. Shale gas reservoirs have been recently considered as suitable geological targets for carbon dioxide (CO2) storage. However, due to the high reactivity of shales to CO2, the mineralogical changes after CO2/brine/shale interactions play a decisive role in defining the sealing properties of shales at geological time scales. Up to date, this issue is rarely investigated; therefore, in this study, a simplified 1-D reactive transport model was constructed based on the properties obtained from Eagle Ford and Mancos shales. PHREEQC software was utilized to simulate equilibrium and kinetic behavior and evaluate the alterations in minerals at 177 atm and 70 °C. The equilibrium model indicated that calcite and clay minerals dissolved in CO2-saturated brine, while quartz grains precipitated, due to the formation of carbonic acid. This behavior confirmed the high reactivity of shales to the injection of CO2-saturated brines. The kinetic model indicated that the geological time scale for CO2/brine/shale interaction can be divided into three phases. Primary minerals alterations occurred during the first 10 years, however, the main alteration in mineralogy occurred between 10 and 100 years, whereas the reactants continued to dissolve in low portions until the equilibrium state was reached beyond 100 years. The model showed that carbonate and clay minerals dissolved during the CO2/brine/shale interaction, which could provide the potential for mineral trapping as an effective sealing mechanism in the middle phases of the storage lifetime in shales, confirming the high potential of shales for CO2 containment. The main observations and conclusions obtained from this work can be easily extrapolated to other shale formations with similar mineral compositions.
... The pressure buildup phenomena increase the risk of hydraulic fracturing of caprock, the reactivity of existing faults, leakage through caprock, leakage through lateral pathways, and ultimately pose a high risk on storage projects and limit the CO 2 storage capacity underground. In the CO 2 -EWR process, similar to that of CO 2 enhanced crude oil recovery, CO 2 functions in a manner similar to a displacement fluid to enhance the recovery of water resource, and CO 2 is trapped underground simultaneously (Bergmo et al., 2011;Damiani et al., 2012;Emami-Meybodi et al., 2015;Santibanez-Borda et al., 2019;Song et al., 2019). The operating procedure of CO 2 -EWR is similar to that of CO 2 -EOR but with much larger well spacing, well injectivity, and flow rate of a single well. ...
Carbon dioxide (CO2) storage in deep saline aquifers is a vital option for CO2 mitigation at a large scale. Determining storage capacity is one of the crucial steps toward large-scale deployment of CO2 storage. Results of capacity assessments tend toward a consensus that sufficient resources are available in saline aquifers in many parts of the world. However, current CO2 capacity assessments involve significant inconsistencies and uncertainties caused by various technical assumptions, storage mechanisms considered, algorithms, and data types and resolutions. Furthermore, other constraint factors (such as techno-economic features, site suitability, risk, regulation, social-economic situation, and policies) significantly affect the storage capacity assessment results. Consequently, a consensus capacity classification system and assessment method should be capable of classifying the capacity type or even more related uncertainties. We present a hierarchical framework of CO2 capacity to define the capacity types based on the various factors, algorithms, and datasets. Finally, a review of onshore CO2 aquifer storage capacity assessments in China is presented as examples to illustrate the feasibility of the proposed hierarchical framework.
... Secondly, CO 2 dissolves in and swells the oil, which also results in decreasing its viscosity [36,37]. Recent studies have suggested that CO 2 injection is more sustainable and effective as compared to water injection in reservoirs [38][39][40][41]. There are also reported benefits of CO 2 injection for enhanced gas recovery [42,43]. ...
The relatively low density and viscosity of carbon dioxide (CO2) in supercritical state create several drawbacks, including gravity override, viscous fingering, water production/treatment problems, and poor proppant transport for the petroleum industry. The introduction of CO2 thickeners offers a promising additive technology with sufficient solubility and viscosity enhancement attributes. The current article reviews the technical advances, challenges, and applicability of thickened CO2 , particularly for hydrocarbon recovery. Different types of thickeners, including polymers, tailor-made surfactants, and small associating compounds, were investigated in terms of their nature, physicochemical traits, cost, and applications. The molecular weight and concentration, shear rate, co-solvent composition, temperature, and pressure play a significant role in the intermolecular forces and miscibility effect of thickeners in the presence of dense CO2. Binary co-polymers (non-fluorinated non-siloxane materials) and small molecule (associating) compounds are promising options for CO2 thickening owing to their enhanced performance, cost-effectiveness, and low ecological footprint. This study provides a comprehensive review of existing technologies, outline the gaps, potential, and required area for improvement.
... CO 2 can also be used as a fracturing fluid and enhance shale gas recovery (ESGR) (Luo et al., 2018). Several studies reported that SCCO 2 can: 1) generate complex fractures with high conductivity (Wanget al., 2019;Song et al., 2019), 2) prevent formation damage (Song et al., 2018), 3) reduce the amount of produced wastewater (Li et al., 2015;Zhenyun et al., 2015), and 4) provide better displacement of the natural pre-adsorbed methane during fracturing (Zhan et al., 2017;Nuttall et al., 2005;Middleton et al., 2015;Lyu et al., 2018;Godec et al., 2013). However, the impact of CO 2 on the pore structure of shale has not been fully understood (Ma et al., 2021). ...
Injection of supercritical CO2 (SCCO2) causes significant changes in the petrophysical properties of shales and affects the integrity of geological storage sites. The alteration of mineralogy and pore structure plays a major role in defining the fluid transport in pours media of shale gas during CO2 storage. In this study, a series of SCCO2 treatment experiments were performed on different types of shales to evaluate the alterations of the pore structure and mineralogy. Two types of shales from Eagle Ford and Mancos fields were treated with SCCO2 and analyzed with scanning electron microscope, X-ray diffraction, and low-pressure nitrogen adsorption before and after 30 days at 70 °C and 18 MPa. The experimental results indicated that SCCO2 affected the mineral composition and changed the macropore structure of shales, due to the adsorption-induced expansion effect. The pore structure of clay-rich shales samples was more affected by CO2 treatment compared to quartz-rich shales, due to the dissolution of clay contents in the former, which reduced the overall pore volume by 24% in Eagle Ford shales. Conversely, the development of micro-cracks in Mancos shale surface created new pores and increased the pore volume by more than 13%. The results from nitrogen adsorption isotherms indicated a prominent alteration in the mesopores structure. The specific surface area and total pore volume of Eagle Ford shale reduced by 35.46% and 11.86% respectively after the SCCO2 treatment, while the specific surface area and total pore volume of Mancos shale increased by 27.4% and 25.92% respectively. A positive correlation was reported between the fractal dimension and specific surface area. It appeared that the surface roughness was reduced in Eagle Ford shale and relatively increased in Mancos shales after the treatment. The obtained results suggested that the adsorption capacity of clay-rich shales could be reduced after the CO2 treatment, while quartz-rich shales displayed a uniformed pore size distribution profile, indicating a possible increase in the adsorption capacity. These findings can provide technical support to further understand the effect of CO2 on the pore structure and mineralogical alteration of shale during geological storage.
... The use of Outcrop samples as an alternative to the real underground sample is standard practice and the one used frequently to study basic geo-mechanical, petro-physical, and geochemical properties of shale [47][48][49]. Researchers in the past have successfully used outcrop samples to test their innovative ideas to develop emerging techniques for application in real field reservoirs [49,50]. A Murg diamond wire bandsaw was used to cut the rough shapes which were then perfected into 50 × 50 × 50 mm cubic shape (Fig. 1a) and 38 × 25 mm cylindrical discs (Fig. 1b). ...
Multi-stage hydraulic fracturing has been identified as a must to develop shale gas reservoirs by increasing the stimulated reservoir volume (SRV). Supercritical CO2 (scCO2) has been studied as an alternating fracturing fluid due to its tendency to solve numerous problems associated with conventional aqueous based hydraulic fracturing such as formation damage, clay swelling, water scarcity and ground water contamination. However, its consequences to the host rock are not well understood. It has been recognized that scCO2-shale interaction alters the petrophysical properties during the long-term exposure of shale into scCO2, far little attention has been paid to understand the impact of this process for the short term. Thus, laboratory fracturing experiments using scCO2 on cubic shale samples (50 × 50 × 50 mm) in true triaxial stress cell (TTSC) were conducted. X-ray computed tomography (CT) imaging and low-pressure N2 adsorption were also performed to gain a deeper understanding of the fluid-rock interactions on the studied shales at a short-time process. Post-fracturing x-ray CT scans revealed a significant reduction, in the range of 14% to 46%, in the aperture of the natural fractures, indicating towards a possible scCO2 induced swelling. Mechanical compression test on the sample results in around 12% reduction in the fracture aperture, ruling out the possibility of confining stress being the key factor behind the fracture closure observed during fracturing. scCO2 soaking and N2 adsorption experiments showed the narrowing down of the macropores after scCO2 treatment implying the adsorption swelling as one of the controlling factors for the reduction of fracture aperture. Taken together, our results suggest that scCO2-shale interactions during the short term process of hydraulic fracturing can contribute to decreasing the conductivity of pathways between matrix and hydraulic fractures and hence adversely affecting the post-fracturing productivity of the rock.
... 26 Supercritical CO 2 for fracking, recovering shale gas, or tight gas/oil, has been recommended by many. 27,28 Fracking for geothermal energy by supercritical CO 2 has been similarly recommended. 29,30 CO 2 has some advantages over water for EGS such as greater power output, smaller parasitic losses, carbon sequestration, and reduced water use. ...
A renewable energy-only grid must couple mutable energy supply such as wind and solar photovoltaic and affordable energy storage by lithium-ion batteries to dispatchable energy supply such as Concentrated Solar Power (CSP) with thermal energy storage (TES) and Enhanced Geothermal Energy (EGS). EGS is centered on the exploitation of the substantial unconventional geothermal energy supplies in the crust of the Earth which is missing permeability and groundwater, with significant opportunities in western Saudi Arabia where the solar resource is also relevant. Regarding conventional geothermal energy, thermal efficiencies of the cycles can be increased to above 30% with EGS, and above 40% through the integration of EGS with CSP and TES, surpassing the 50% efficiency mark adopting advanced ultra-supercritical (AUSC) technologies.
... Because of potential effect of leak-off on fracture creation, the fluid flux calculation is a key focus in our work. In some models, a leak-off coefficient is introduced to adjust the leak-off between the fracture and the matrix (Liu, Qu, et al., 2018;Song et al., 2019). However, a clear interpretation of the selection of this coefficient for different fluids is missing. ...
Hydraulic fracturing of tight subsurface formations has mainly been conducted using water. Waterless hydraulic fracturing by CO2 may have advantages over fracturing by water. The challenge has been numerical simulation of the process. In this work, we conduct a comprehensive study on 2D hydraulic fracturing simulation by water, CO2, and nitrogen. The simulations are based on the phase‐field; the results are compared with the lab data. We first present advances in simulation of fluid exchange between the fractures and the rock matrix. The conventional nodal‐based finite element method may give rise to unphysical negative pressure around the tip and fracture notch. We demonstrate that the mixed hybrid finite element method gives non‐negative pressure distribution. Next, we examine the effect of inertial term on fracture configuration and observe branching by CO2 under dynamic formulation with a low critical energy release rate. Lastly, we find from our simulations that in shale rocks, the critical energy release rate is the lowest for CO2, followed by nitrogen, and then water. Consequently, CO2 provides the highest fracture surface area and fracture intensity. In a sandstone sample we find nitrogen has a lower energy release rate than water. As a result, the fracture surface area is higher for nitrogen than water. Our simulation results confirm that the phase‐field method may incorporate fluid‐rock surface free energy without the need for various parameter adjustments.
... Breakdown pressure is the pressure required to create the fracture in the reservoir and allows the fracturing fluid to penetrate in the given formation [4][5][6][7][8]. Fractures are created by injecting a pressurized fluid that provides conductive paths between the formation matrix, natural fractures, and the wellbore [9,10]. ...
The process of well cleanup involves the removal of an impermeable layer of filter cake from the face of the formation. The inefficient removal of the filter cake imposes difficulty on fracturing operations. Filter cake's impermeable features increase the required pressure to fracture the formation. In this study, a novel method is introduced to reduce the required breakdown pressure to fracture the formation containing the water-based drilling fluid filter cake. The breakdown pressure was tested for five samples of similar properties using different solutions. A simulated borehole was drilled in the core samples. An impermeable filter cake using barite-weighted drilling fluid was built on the face of the drilled hole of each sample. The breakdown pressure for the virgin sample without damage (filter cake) was 6.9 MPa. The breakdown pressure increased to 26.7 MPa after the formation of an impermeable filter cake. Partial removal of filter cake by chelating agent reduced the breakdown pressure to 17.9 MPa. Complete dissolution of the filter cake with chelating agents resulted in the breakdown pressure approximately equivalent to the virgin rock breakdown pressure, i.e., 6.8 MPa. The combined thermochemical and chelating agent solution removed the filter cake and reduced the breakdown pressure to 3.8 MPa. Post-treatment analysis was carried out using nuclear magnetic resonance (NMR) and scratch test. NMR showed the pore size redistributions with good communication between different pores after the thermochemical removal of filter cake. At the same time, there was no communication between the different pores due to permeability impairment after filter cake formation. The diffusion coupling through NMR scans confirmed the higher interconnectivity between different pores systems after the combined thermochemical and chelating agent treatment. Compressive strength was measured from the scratch test, confirming that filter cake formation caused added strength to the rock that impacts the rock breakdown pressure. The average compressive strength of the original specimen was 44.5 MPa that increased to 73.5 MPa after the formation of filter cake. When the filter cake was partially removed, the strength was reduced to 61.7 MPa. Complete removal with chelating agents removed the extra strength that was added due to the filter cake presence. Thermo-chemical and chelating agents resulted in a significantly lower compressive strength of 25.3 MPa. A numerical model was created to observe the reduction in breakdown pressure due to the thermochem-ical treatment of the filter cake. The result presented in this study showed the engineering applications of thermochemical treatment for filter cake removal. Citation: Tariq, Z.; Aljawad, M.S.; Mahmoud, M.; Alade, O.; Kamal, M.S.; Al-Nakhli, A. Reduction of Breakdown Pressure by Filter Cake Removal Using Thermochemical Fluids and Solvents: Experimental and Numerical Studies. Molecules 2021, 26, 4407. https://doi.
... 61 Technical developments such as cyclic injection of carbon dioxide, and huff and puff operations, may be considered to further increase the efficiency in field operations. Compared with water, CO 2 injection require a lower pressure for fracturing and generates more complex fracturing networks, 62 while variations between induced microseismicity during water or CO 2 injection requires careful studies. ...
Injection of CO2 into shale reservoirs to enhance gas recovery and simultaneously sequester greenhouse gases is a potential contributor towards the carbon-neutral target. It offers a low-carbon, low-cost, low-waste and...
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.
The behavior of gas flow in fractures is crucial for evaluating shale gas production. This study focused on the coupling relationships between effective stress, surface roughness, and gas flow behavior in shale fractures. Three fractured shale specimens were generated using Brazilian splitting tests. The fracture surfaces were then scanned using a 3D profilometer to quantify surface roughness in two and three dimensions. Gas flow tests were conducted on the fractured shale specimens under varying effective stresses (1–15 MPa). The results showed that the Spc (arithmetic mean curvature of crest points) had little effect on nonlinear flow at low effective stress (1–5 MPa) but it became more pronounced at high effective stress (10–15 MPa) due to fracture channel narrowing. Then, the inertial force effect regulated by effective stress and roughness was enhanced as the Reynolds number increased. A friction coefficient model based on the nonlinear effect factor and Reynolds number is proposed and it fits the experimental data well. Furthermore, that effective stress plays a dominant role in permeability loss compared to fracture surface roughness and fluid properties, and exponential function better describes fractured shale permeability under effective stress than power function. Finally, during fracture closure under effective stress, Ra (arithmetic mean roughness) correlated positively with the self-supporting effect of fracture surfaces. As Spc increased, fracture surface peaks became sharper and more easily damaged due to excessive extrusion between contact surfaces.
Carbon dioxide (CO2) fracturing as an alternative to hydrofracturing is one of the most effective fracking techniques for shale gas extraction. As the water-based fracturing fluid can cause formation damage, clay swelling, and water blocking in shale, it is essential to replace it with CO2 fracturing fluids. The CO2 fracturing technique utilizes comparatively fewer chemicals and water, and has a high capacity for adsorbing CO2 with CH4. The CO2 fracturing technique is an appropriate fracturing technique as compared to other fracturing fluids. As the shale reservoirs are heterogenous, fracturing techniques are controlled by several parameters. Therefore, the shale reservoirs need to analyze adequately at a different scale. 3D modeling is essential to understand the efficacy of fracturing in unconventional reservoirs. The present study demonstrates the 3D geo-mechanical model through reservoir simulation techniques, and we estimate the gas recovery for a shale reservoir. The multi-stage fracturing tests were conducted on the unconventional reservoir using the fracture model to assess the heterogeneity, and change in the distance between the fractures. This study also analyzes the effects due to the space distance and fracture conductivities. The simulation study is conducted under different conditions by using CO2 as a fracturing fluid. The results suggest that the shale gas recovery rate increased by approximately 3 to 7% with the changes in fracture half-length, spacing, and fracture numbers.
The development of a geothermal system can supply low-carbon electricity to support the raising energy demand under the energy transition from fossil fuel to renewables. CO2 can substitute for water for energy recovery from geothermal reservoirs owing to its better mobility and higher heat capacity. Additionally, trapping injected CO2 underground can achieve environmental benefits by targeting Greenhouse gas (GHG) mitigation. In this study, different flow schemes are established to assess heat mining and geological CO2 sequestration (CCS) by injecting CO2 for the purpose of an enhanced geothermal system. The Qiabuqia geothermal field in China is selected as a study case to formulate the geothermal reservoir simulation. The results show that a pure CO2 injection into a water-saturated reservoir can provide the best performance in heat mining. Besides, this operational strategy can also provide extra benefits by producing 6.7% CO2 retention. The generated geothermal electricity under a pure CO2 injection into a CO2-saturated formation is the lowest, while its 42.1% of CO2 retention shows a promising CCS performance and the large volume of stored CO2 can supply some profits by carbon credit. Considering the assessment on heat mining and CCS, the pure CO2 injection into a water-saturated reservoir is recommended for the operation of an EGS. Under this flow strategy, well spacing, production pressure difference and fluid injection temperature are dominated in geothermal energy production. Three factors, including well spacing, production pressure difference and fracture conductivity, influence the CO2 storage capacity. In operating an EGS, a larger well spacing, a lower injection temperature and a lower fracture conductivity are suggested. While the optimal production pressure difference should be further determined to balance its effect on geothermal production and CO2 storage since it presents an opposite effect on these two parts. This work demonstrates the feasibility of heat mining associated with CO2 geological permanent storage in an EGS by injecting CO2. The proposed study proves that not only the sufficient and sustainable energy can be supplied but also a significant amount of CO2 emission can be eliminated simultaneously. In addition, the investigation of geothermal energy production and CO2 geological sequestration under different operational parameters can provide profound guidance for the operators.
Accurate modeling of CO2/CH4 competitive adsorption behavior is a critical aspect of enhanced gas recovery associated with CO2 sequestration in organic-rich shales (CO2-ESGR). It not only improves the ultimate recovery of shale gas reservoirs that satisfies the increasing energy demand but also provides permanent geologic storage of atmospheric CO2 that contributes to the net-zero energy future. Determining a CO2/CH4 adsorption ratio is essential for the performance prediction of shale gas reservoirs and the evaluation of CO2 storage potential. However, experimental adsorption measurements are expensive and time-consuming that may not always be available for shale reservoirs of interest or at the investigated geologic conditions, and as a result, a sorption ratio cannot be assessed appropriately. Traditional models such as a Langmuir model are highly dependent on extensive experiments and cannot be widely applied. Therefore, a unified adsorption model must be developed to predict the CO2/CH4 competitive adsorption ratios, which is essential for CO2 sequestration and exploitation of natural gas from shale reservoirs.
In recent years, the development of machine learning algorithms has significantly improved the accuracy and computational speed of prediction. In this work, we conducted a comparative machine learning algorithm study to effectively forecast the maximum CO2 adsorption capacity and CO2/CH4 competitive adsorption ratios. Four sensitive input parameters (i.e., temperature, total organic carbon, moisture content, and maximum adsorption capacity of CH4) were selected, along with their 50 data points collected from the existing literature.
The artificial neural network (ANN), XGBoost, and Random Forest (RF) algorithms were investigated. By comparing the mean absolute errors (MAE) and coefficients of determination (R2), it was found that the ANN models can successfully forecast the required outputs within a 10% accuracy level. Furthermore, the descriptive statistics demonstrated that the CO2/CH4 competitive adsorption ratios were generally from 1.7 to 5.6. The proposed machine learning algorithm framework will provide insights beyond the isothermal conditions of classical adsorption models and the solid support to CO2-ESGR processes into which competitive adsorption can be a driven mechanism.
Hydraulic fracturing is widely used in shale gas development, while it could cause decline in production in water-sensitive formations. Using CO2 for reservoir fracturing, injection to enhance gas recovery, and sequestration in depleted shale reservoirs can solve this problem, increase shale gas production, and store CO2 underground. Given the high expense of these CO2 techniques, the trade-off between the rising cost of deploying CO2 techniques and the benefit of increased shale gas production influences the technology portfolios for shale gas development. Financial incentives for carbon credits can provide compensation for the cost of CO2 techniques, further influencing the technology portfolios. Currently, questions remain regarding the optimal technology portfolios for achieving cost-effective shale gas development under different reservoir conditions and the impacts of the carbon price incentive. Here, we propose a novel optimization model that simultaneously integrates the hydraulic fracturing, CO2 fracturing, CO2 injection, and CO2 sequestration techniques to investigate the optimal technology mix for cost-effective shale gas development. We select the non-water sensitive formations and water sensitive formations as two representative scenarios. The results show that to cost-effectively develop shale gas, hydraulic fracturing is preferred in the non-water sensitive scenario whereas CO2 fracturing and CO2 injection are preferred in the water sensitive scenario. The synergistic deployment of CO2 fracturing and CO2 injection techniques can not only improve economic performance but also sequestrate more CO2. Our findings provide policy makers with critical insights into achieving cost-effective shale gas development while curbing carbon emissions.
Unconventional oil reservoirs are usually classified by extremely low porosity and permeability values. The most economical way to produce hydrocarbons from such reservoirs is by creating artificially induced fractures. To design the hydraulic fracturing jobs, true values of rock breakdown pressure is required. Conducting hydraulic fracturing experiments in the laboratory is a very expensive and time consuming process. Therefore, in this study, different machine learning models were efficiently utilized to predict the breakdown pressure of the tight rocks. In the first part of the study, a comprehensive hydraulic fracturing experimental study was conducted on various rock specimens, to measure the breakdown pressure. A total of 130 experiments were conducted on different rock types such as shales, sandstone, tight carbonates, and synthetic cement samples. Rock mechanical properties such as Young's Modulus E, Poisson's ratio, Unconfined Compressive strength (UCS), and indirect tensile strength sigma_t were measured before conducting hydraulic fracturing tests. Machine learning models were used to correlate the breakdown pressure of the rock as a function of fracturing experimental conditions and rock properties. In the machine learning model, we considered experimental conditions including injection rate, overburden pressures, and fracturing fluid viscosity, and rock properties including Young's Modulus, Poisson's ratio, Unconfined Compressive strength (UCS), and indirect tensile strength, porosity, permeability, and bulk density. Machine learning models include Random Forest (RF), Decision Trees (DT), and K-Nearest Neighbor (KNN). During training of ML models, the model hyper-parameters were optimized by grid search optimization approach. With the optimal setting of the ML models, the breakdown pressure of the unconventional formation were predicted with an accuracy of 95%. The proposed methodology to predict the breakdown pressure of unconventional rocks can minimize the laboratory experimental cost of measuring fracture parameters and can be used as a quick assessment tool to evaluate the development prospect of unconventional tight rocks.
This work provides a general analysis method for the crack detection in shales. The acoustic emission (AE) testing with data recovery is proposed for determining the crack modes and positions in the test and analysis process of the shale fracturing experiment. A fracturing and in situ AE monitoring system is constructed to collect the experimental data in at least six channels for the crack detection, and the source positions output from AE testing represent the positions of cracks. Due to some uncontrollable reasons, such as the poor coupling between sensors and sample and the sudden failure of the sensors, some parts of experimental data are missing during the experiments. Therefore, a data recovery neural network algorithm based on wavenet model is introduced to reconstruct the missing parts of experimental data in the waveforms. Since the accuracy of data recovery is not satisfying based on the collected experimental data, the interpolation of experimental data is performed to refine the data which can obviously improve the accuracy of data recovery. After all the required experimental data have been recovered, the crack mode for each crack can be determined based on the moment tensor analysis. This analysis method can be extensively applied to the shale crack detection.
Few studies focus on the plastic deformations of inorganic semiconductors because they are usually brittle and do not deform easily. Here, a peculiar internal shear stress originated from the entropy deletion of CO2 in the tunnels of non‐van der Waals VO2 crystal, is employed to introduce hierarchical plastic deformations, including dislocations, point vacancies, twins, and amorphous bands. The strength of such stress field increases by more than three orders of magnitude compared to that of external experimental CO2 pressure. We further demonstrate that 2D amorphous structures can be obtained by the synergetic effect of hierarchical deformations in 3D crystal.
Intermediate‐temperature proton ceramic fuel cells (PCFCs)–a promising power generation technology–have attracted significant attention in recent years because of their unique advantages over conventional high‐temperature solid oxide fuel cells and low‐temperature proton exchange membrane fuel cells. The cathodes of PCFCs simultaneously require efficient channels for proton, oxide‐ion, and electron transfer; therefore, designing and engineering cathode materials with tailorable H+, O2−, and e− conductivities are crucial for improving PCFC performance. Despite significant efforts and critical progress in this field, exploring the desired cathode materials remains challenging. This review provides a comprehensive and critical overview of oxide materials for PCFC cathodes, particularly triple H+/O2−/e− conductors. Their proton uptake, conduction mechanisms, and structure–property relationships are focused on to guide future material design. In addition, the electrochemical performance of these cathode materials in PCFCs is discussed and the electrochemical performance gaps among PCFCs with different types of cathode materials are defined. Finally, perspectives on the development of high‐performance PCFCs are proposed. This review summarizes the recent progress and perspectives in advanced cathodic materials and the application for the cathodes of protonic ceramic fuel cells (PCFCs). The relationships between three types of cathodic materials and their electrochemical performance in PCFCs are clarified. Finally, the future directions for machine learning accelerating the development of high‐performing PCFCs are pointed out.
The formation of hydraulic fracture-network is an important goal for stable and increased production of unconventional oil and gas resources. However, due to the extremely complex mechanical behavior of hydraulic-fracture propagation, there is still a lack of fine, effective and systematic evaluation methods on 3D fracture-network structure. The quantitative characterization of hydraulic-fractures is of great significance to reveal the law of fracture propagation and to evaluate the reservoir stimulation effectiveness reasonably. Although the micro-cracks evolution process follows a random rather than deterministic pattern, the overall fracture morphology is featuring statistical regularity. In this study, after the indoor hydraulic-fracturing simulation experiments of the tight sandstone specimens, 3D optical scanning was used to visualize the fracture-network. On this basis, two aspects of quantitative statistics of 3D complex fracture-networks were established by plane and sphere cuttings for the first time, including angle distribution statistics and spatial variation statistics. Comparative analyses with reported methods showed that, the overall deflection of the macroscopic fracture-networks varies synchronously with the local roughness of the main hydraulic fractures closest to the wellbore, which satisfied exponential function or power-law function relationship between them. The variation of the area proportion with the propagation radius reflects the specific fracture propagation process such as crack initiation, bifurcation and arrest, and could be used to assess the complexity of the fracture-network. Moreover, a new stimulation evaluation index Es was established by comprehensively considering the stimulated-reservoir-area, the dispersion degree of the angle distribution and the complexity of spatial variation for 3D fracture-network. The insights gained warrant further applicability on hydraulic-fracturing in the actual engineering scale.
Unconventional reservoirs such as gas shales and tight gas sands require technology-based solutions for optimum development because of the undeveloped matrix pores and poor permeability. Hydraulic fracturing is one of the most critical technologies. The quantitative characterization of hydraulic fractures is of great significance to the stimulation evaluation of the reservoir, but there is still a lack of fine, effective and systematic evaluation methods. 3D optical scanning technology is widely used in the quantitative characterization of rock fracture morphology for its advantages of high speed, convenience, high precision, and nondestructive testing. In this study, after the indoor hydraulic-fracturing simulation experiments, 3D optical scanning was used to visualize the fracture network. On this basis, two aspects of quantitative evaluation methods for stimulation effectiveness were established, including: (1) evaluating the local conductivity (permeability) of different fractures by cutting hydraulic-fracturing samples. Then combining local conductivity of different fractures with the overall stimulated reservoir area, which could be more reasonable to evaluate the stimulation scope of the reservoir; (2) calculating the fractal dimension (FD) of the 3D spatial structure based on the point-cloud processing, which could directly reflect the complexity of the fracture network. Finally, a new evaluation index for stimulation (Es) was established to comprehensively assess the stimulation effectiveness of the reservoir, which was applied and verified through the indoor fracturing simulation experiments of tight sandstone from the Ordos Basin, China.
The mode I fracture toughness is a critical parameter which defines the rock’s resistance to crack propagation, especially in hydraulic fracturing. Recently, Supercritical carbon dioxide (Sc-CO2) has been proposed as a fracturing fluid candidate in hydraulic fracturing stimulations of shale reservoirs. However, its effects on fracture toughness transition and crack propagation behaviors have not been understood well. In this study, we performed a series of semicircular bend specimens (SCB) before the Longmaxi shale specimens’ saturation. Three-point bending tests along divider orientation showed that after Sc-CO2 saturation, mode I fracture toughness (KIC) , elastic modulus (E) and absorbed energy (Ue) of shale were decreased by 22.1%, 24.5% and 44.3%, respectively. High speed camera images indicated that after Sc-CO2 saturation, mode I crack directly propagated straight along artificial pre-crack direction, decreasing the degree of crack deviation as in KIC. The results of Cronos high-precision 3D scanning system and scanning electron microscopy (SEM) revealed complicated fracture mechanisms (transgranular, intergranular and mutual coupling crack mechanisms) of shale after Sc-CO2 saturation, which reduced the roughness and area of fracture crack surface. The generation of pore and cracks was the main reason for the decrease of shale resistance to fracture. Furthermore, Sc-CO2 saturated shale specimens only needed to absorb less energy to more rapidly cause the initiation and propagation of mode I cracks with the main fracture mode being transgranular cracks.
A renewable energy-only grid made of wind and solar photovoltaic (PV) energy supply needs huge, unaffordable energy storage by batteries (BES). Thus, the supply of dispatchable or constant renewable energy, hydro, biomass, concentrated solar power (CSP) with internal thermal energy storage (TES) and geothermal is necessary. Geothermal energy is set to grow dramatically thanks to enhanced geothermal systems (EGS), where hydraulic fracturing may create geothermal fluid sources in the amount and quality needed in many locations where naturally unavailable. The manuscript summarizes the challenges and opportunities of EGS, a technology where geoscience and energy engineering meet to harvest a novel, significant, quality, renewable energy source. Then, it foresees as EGS could become a key contributor to balancing a grid renewable energy only with affordable BES, standalone or integrated with TES or CSP and TES.
The synthesis of sustainable methanol and ethylene glycol via hydrogenation of ethylene carbonate (EC) has caught researcher's growing interests on account of the indirect chemical utilization of CO2. Core-shell [email protected] catalysts with random nanoporous network of graphite oxide were synthesized via a simple method of ultrasonic [email protected] catalysts were analyzed systematically by N2 physisorption, TGA measurement, XRD, FT-IR, Raman, TEM, SEM, and XPS (XAES). In particular, the mentioned method was confirmed to be effective to fabricate the high dispersity core-shell [email protected] catalysts through promoting the specific surface area. The as-prepared [email protected] catalyst was then successfully applied in the hydrogenation of CO2-derived EC to produce methanol and ethylene glycol. A high TOF of 1526 mgEC•gcat⁻¹•h⁻¹ could be attained in EC hydrogenation at the reaction temperature of 493 K. Accordingly, the correlation of catalytic structure and performance disclosed that the synergistic effect between Cu⁺ and Cu⁰ was responsible for achieving high activity of the catalyst. In addition, the reusability result of [email protected] catalyst suggested that graphite oxide shell structure could decrease the aggregation of copper particles, thus enhanced the stability of copper-based catalysts. DFT calculation result suggested that the involvement of carbon film on copper was favorable for the stabilization of the active sites. This study is helpful for developing new and stable catalytic system for chemical utilization of CO2 to synthesize commodity methanol and ethylene glycol indirectly.
Supercritical CO2 fracturing is a potential waterless fracturing technique which shows great merits in eliminating reservoir damage, improving shale gas recovery and storing CO2 underground. Deep insight into the proppant-transport behavior of CO2 is required to better apply this technique in the engineering field. In the present paper, we adopted a coupled Computational Fluid Dynamics and Discrete Element Method (CFD-DEM) approach to simulate the proppant transport in a fracking fracture with multiple perforation tunnels. Previous experiments were first simulated to benchmark the CFD-EDM approach, and then various pumping schedules and injection parameters (injection location, multi-concentration injection order, multi-density injection order and injection temperature) were investigated to determine the placement characteristics of proppant. Results indicate that the swirling vortex below the injection tunnels dominates the proppant diffusion in the fracture. The velocity of fluid flow across the proppant bank surface in multi-concentration injection shows a positive correlation with the proppant concentration. Injecting high-density proppant first can promote the transportation of low-density proppant injected later in the fracture to a certain extent Decreasing the initial injection temperature of supercritical CO2 slurry helps enhance the particle-driving effect of fluid and improve the performance of supercritical CO2 in carrying proppant.
Fracturing is the necessary means of tight oil development, and the most common fracturing fluid is slickwater. However, the Loess Plateau of the Ordos Basin in China is seriously short of water resources. Therefore, the tight oil development in this area by hydraulic fracturing is extremely costly and environmentally unfriendly. In this paper, a new method using supercritical carbon dioxide (CO2) (ScCO2) as the prefracturing energized fluid is applied in hydraulic fracturing. This method can give full play to the dual advantages of ScCO2 characteristics and mixed-water fracturing technology while saving water resources at the same time. On the other hand, this method can reduce reservoir damage, change rock microstructure, and significantly increase oil production, which is a development method with broad application potential.
In this work, the main mechanism, the system-energy enhancement, and flowback efficiency of ScCO2 as the prefracturing energized fluid were investigated. First, the microscopic mechanism of ScCO2 was studied, and the effects of ScCO2 on pores and rock minerals were analyzed by nuclear-magnetic-resonance (NMR) test, X-ray-diffraction (XRD) analysis, and scanning-electron-microscope (SEM) experiments. Second, the high-pressure chamber-reaction experiment was conducted to study the interaction mechanism between ScCO2 and live oil under formation conditions, and quantitively describe the change of high-pressure physical properties of live oil after ScCO2 injection. Then, the numerical-simulation method was applied to analyze the distribution and existence state of ScCO2, as well as the changes of live-oil density, viscosity, and composition in different stages during the full-cycle fracturing process. Finally, four injection modes of ScCO2-injection core-laboratory experiments were designed to compare the performance of ScCO2 and slickwater in terms of energy enhancement and flowback efficiency, then optimize the optimal CO2-injection mode and the optimal injection amount of CO2 slug.
The results show that ScCO2 can dissolve calcite and clay minerals (illite and chlorite) to generate pores with sizes in the range of 0.1 to 10 µm, which is the main reason for the porosity and permeability increases. Besides, the generated secondary clay minerals and dispersion of previously cemented rock particles will block the pores. ScCO2 injection increases the saturation pressure, expansion coefficient, volume coefficient, density, and compressibility of crude oil, which are the main mechanisms of energy increase and oil-production enhancement. After analyzing the four different injection-mode tests, the optimal one is to first inject CO2 and then inject slickwater. The CO2 slug has the optimal value, which is 0.5 pore volume (PV) in this paper.
In this paper, the main mechanisms of using ScCO2 as the prefracturing energized fluid are illuminated. Experimental studies have proved the pressure increase, production enhancement, and flowback potential of CO2 prefracturing. The application of this method is of great significance to the protection of water resources and the improvement of the fracturing effect.
To solve the problems caused by the water-based fracturing fluid in the process of shale gas development in China, a technical idea of integrated supercritical CO2 enhanced shale gas recovery and geological sequestration (CO2-ESGR) was developed. The propagation laws of fractures induced by supercritical CO2 fracturing, the thermodynamic and dynamic principles of CO2 displacing CH4 and the mechanisms of CO2 enhanced shale gas recovery and CO2 geological sequestration were investigated with supercritical CO2 fracturing, CO2-CH4 competitive adsorption, and CO2-water-shale interaction as the beginning point. The whole-life-cycle carbon emission of CO2-ESGR technology was analyzed and its prospect was forecasted. Supercritical CO2 fracturing has lower fracture initiation pressure and induced more complicated fracture networks in shale gas reservoirs. The adsorption capacity and orderliness of CO2 on shale are much higher than those of CH4, so it can effectively replace CH4 and con-sequently improve shale gas recovery. Shale reservoirs have a huge potential of large-scale CO2 sequestration and their sequestration mechanisms are mainly adsorption and mineralization reaction. If an appropriate reservoir is selected, CO2 sequestration can offset the CO2 emission in the whole life cycle of shale gas development and utilization, and thereby realize CO2 zero emission or even negative emission in the whole process of shale gas development and utilization.
Hydraulic fracturing is one of the common stimulation technologies which is used for shale gas or oil production. But the use of conventional hydro- fracturing has lot of drawbacks including water scarcity and environmental disaster, clay swelling, wellbore instability, etc. This paper discusses CO2 fracturing treatment in shale formation as an alternative of water base fracturing in shale reservoirs. The paper also includes history of CO2 fracturing, and a detailed study about the different parameters of the shales which control the fracturing performance. A key focus of the study is to understand about the CO2– shale interaction. As supercritical CO2 (SCO2) has benefits for the effectiveness of gas production from the shale reservoirs for reduction of environmental footprint.
Unconventional reservoirs are characterized by their extremely low permeabilities surrounded by huge in-situ stresses. Hydraulic fracturing is a most commonly used stimulation technique to produce from such reservoirs. Due to high in situ stresses, breakdown pressure of the rock can be too difficult to achieve despite of reaching maximum pumping capacity. In this study, a new model is proposed to predict the breakdown pressures of the rock. An extensive experimental study was carried out on different cylindrical specimens and the hydraulic fracturing stimulation was performed with different fracturing fluids. Stimulation was carried out to record the rock breakdown pressure. Different types of fracturing fluids such as slick water, linear gel, cross-linked gels, guar gum, and heavy oil were tested. The experiments were carried out on different types of rock samples such as shales, sandstone, and tight carbonates. An extensive rock mechanical study was conducted to measure the elastic and failure parameters of the rock samples tested. An artificial neural network was used to correlate the breakdown pressure of the rock as a function of fracturing fluids, experimental conditions, and rock properties. Fracturing fluid properties included injection rate and fluid viscosity. Rock properties included were tensile strength, unconfined compressive strength, Young's Modulus, Poisson's ratio, porosity, permeability, and bulk density. In the process of data training, we analyzed and optimized the parameters of the neural network, including activation function, number of hidden layers, number of neurons in each layer, training times, data set division, and obtained the optimal model suitable for prediction of breakdown pressure. With the optimal setting of the neural network, we were successfully able to predict the breakdown pressure of the unconventional formation with an accuracy of 95%. The proposed method can greatly reduce the prediction cost of rock breakdown pressure before the fracturing operation of new wells and provides an optional method for the evaluation of tight oil reservoirs.
Renewable energy is part of the national sustainable energy mix for the Kingdom of Saudi Arabia (KSA). Relevant contributors are wind, and more importantly solar photovoltaic. Wind and solar photovoltaic (PV) are cheap, but they are suffering from variability, unpredictability, and in the case of solar PV, also intermittency. As the lithium-ion battery energy storage needed to make a stable grid only accepting these supplies is unaffordable, dispatchable renewable energy technologies are under study. Concentrated solar power (CSP) with thermal energy storage (TES) is the most promising opportunity. Requesting significant R&D, but having a large potential, enhanced geothermal systems (EGS) may help in the future, especially if coupled to CSP. Other relevant help may come from waste valorization. A renewable only grid managed by artificial intelligence (AI) operator will have to couple variable, unpredictable, and intermittent renewable energy supplies with battery energy storage and dispatchable renewable energy.
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.