ABSTRACT: Coupled hydro-mechanical simulations are by now a standard tool for reservoir modeling. However, challenges remain regarding the proper implementation of faults into such reservoir-scale numerical models which result mainly from the scale difference between the element size of the numerical grid and the internal heterogeneity of real fault zones. In this study, we present an AI-based upscaling approach from detailed fault zones to homogenized fault properties in finite element models. The detailed fault zone model contains a fault core with shear bands and host rock lenses as well as accompanying damage zones with a fracture density decreasing with distance from the fault core. This detailed fault zone model is automatically compared by using the Structural Similarity Index and difference images with a database of 432 models describing the fault zone as one uniform material homogenizing the different fault zone units. The goal is to introduce a new upscaling workflow of hydro-mechanical fault zone properties in reservoir-scale simulations through a database driven approach to represent the fault in a numerical simulation with an optimal grid size while maintaining the bulk effect of a detailed fault zone description on fluid flow, stress and deformation and thus, improving the predictive power of reservoir-scale simulations. 1. Introduction Faults are a common feature in the subsurface and often have a high impact on a variety of geotechnical engineering and engineering geology tasks like tunneling (Schubert and Riedmüller, 1997; Schubert and Riedmüller, 2000; Jeon et al., 2004; Schubert et al., 2006; Zhang et al., 2006; Schubert, 2009; Kun and Onargan, 2013; Paltrinieri et al., 2015), mining (Brady and Brown, 1993; Burtan et al., 2014; Sainoki and Mitri, 2015; Kushwaha et al., 2016; Wang et al., 2016), nuclear waste storage sites (Martin and Lanyon, 2003; Guglielmi et al., 2017; Jaeggi et al., 2017; Park et al., 2020) or reservoir related projects like hydrocarbon production (Wiprut and Zoback, 2002; Cuisiat et al., 2010), geothermal energy (Gan and Elsworth, 2014; Loveless et al., 2014; Duwiquet et al., 2019; Anyim and Gan, 2020) and more recently the storage of CO2 in the underground (Carbon Capture and Storage - CCS; (Nagelhout and Roest, 1997; Vidal-Gilbert et al., 2009; Vidal-Gilbert et al., 2010; Morris et al., 2011; Orlic et al., 2011; Rinaldi et al., 2014). Faults in the subsurface not only have a profound impact on fluid flow, but also effect the stress field in their vicinity. In addition, pore pressure changes due to injection or production can induce slippage and fault reactivation, respectively (Pereira et al., 2014; Rueda et al., 2014; Sanchez et al., 2015; Haug et al., 2018). This may cause induced seismicity, land subsidence and well collapse (Segall et al., 1994; Morton et al., 2006; Chan and Zoback, 2007; Vilarrasa et al., 2017). Fault reactivation may also breach the reservoir seal causing up-fault leakage and allowing fluid migration due to enhanced permeability inside the fault zone (Wiprut and Zoback, 2000; Cuisiat et al., 2010; Faulkner et al., 2010). In order to prevent these hazards numerical modelling is a well-established tool in the industry. Both fluid flow simulations (Manzocchi et al., 2008; Qu et al., 2015) and geomechanical modeling have turned out to be of tremendous help when trying to gain quantitative insights into the hydraulic behavior as well as spatial distribution of stress and strain on the reservoir-scale (Geertsma, 1973; Segall et al., 1994; Fisher and Jolley, 2007; Ferronato et al., 2008; Orlic and Wassing, 2012). Due to the interaction of fluid flow and mechanical behavior, fully-coupled hydro-mechanical simulations gain more and more importance (Cappa and Rutqvist, 2011; Fachri et al., 2016; Serajian et al., 2016; Schuite et al., 2017). Since faults are important features in the subsurface a proper incorporation of faults into such hydro-mechanical models is of crucial relevance for various reasons. However, challenges for the proper implementation of faults into reservoir-scale numerical models remain (Chan and Zoback, 2007; Fredman et al., 2007; Faulkner et al., 2010; Orlic and Wassing, 2012). The three main challenges arise from the need to incorporate faults into geomechanical FE models: (1) How can the small-scale (centimeters to meters) heterogeneity of faults and fault zones be adequately described regarding the typical cell size of FE reservoir models of tens to hundreds of meters and (2) how can the geometry of the FE grid properly honor the fault geometry? (3) How can reasonable, fault-specific material parameters be achieved or estimated from literature sources to populate the hydro-mechanical model?

ABSTRACT: The nonlinear oil flow through porous media near a sealing fault has a key role in the petroleum reservoir engineering because the existence of sealed zones in many types of reservoir rocks present in the world. This work proposes a new dimensionless unsteady 2-D permeability pore pressure-dependent model for a wellbore near a sealing fault. The analytical solution is based on an integro-differential solution of nonlinear hydraulic diffusivity equation (NHDE) through Green's Functions (GF's). The model also considers the variation in the properties of the rock and the fluid present inside its pores. The unsteady 2-D pressure field is described by the sum of two exponential integral functions Ei(x D , y D , t D ) , that constitute a combined flow (radial, near to the wellbore) and linear (near to the sealing fault). This type of flow in geosciences and petroleum engineering literature is known as pseudo-radial flow. The authors also implement the new model in Matlab ® software in order to evaluate the general solution, so as initial and boundary conditions. The model calibration is performed through a porous media oil flow simulator, which showed a high convergence. The permeability functions k(p) for two reservoir rock layers are obtained through laboratory correlations, generated from synthetic field data. Authors conclude that general solution of NHDE is given by the sum of slightly compressible flow solution P wD (t D ) and the first order term of the series asymptotic expansion, m wD (1) (t D ) . This second term of the series expansion is obtained by solving a Volterra's second kind integro-differential equation in Matlab and is responsible for all the nonlinearities of the combined oil flow. Results of this research showed that when the fault presence begins to contribute to the pressure drop at the well, the drawdown data increasingly departs from the semilog straight line. After a long transitional period, a second straight line with double slope can be noticed. The authors also realized that the graphs in log-log and semi-log plot showed excellent agreement when compared to the numerical simulator, presenting errors less than 0.5%.

ABSTRACT: The permeability characteristics of tailings are the basis of analyzing the stability of tailings dam. Particle size is an important factor affecting the permeability of tailings. This study carried out soil physical properties and permeability test for undisturbed samples obtained from the borehole to analyze the sedimentary characteristics on dry beach surface during the damming process. The permeability characteristics of tailings with different particle sizes were studied. Combining with engineering practice, the seepage stability of tailings dam was analyzed, as well as the variation of dam saturation line under normal operation condition and flood condition. The results suggested that, the tailings particles gradually became finer along the dry beach towards the reservior and the particle size decreased slightly with the depth. The permeability coefficient of tailings increased linearly with the increase of particle size. Under flood condition, the saturation line was uplifted as a whole, and overflowed at the highest sub-dam platform. The water level in the reservior increased by 1.2m. This study can provide an important theoretical basis for further research on the stability of tailings dams. 1. Introduction Tailings are the part of separation operation in ore dressing which can not be used for production because of the low content of useful target components (Rico et al., 2008).In general, tailings can be stored by the construction of tailings ponds (Xie et al., 2009). The tailings pond is an important part of the mine, and its operation status is related to the smooth progress of the mine's production and construction.Once the tailings dam breaks, it will cause serious loss to people's life and property, and also destroy the environment.For example, on September 8th, 2008, a huge faliure occurred at Pingdong tailings pond in Xiangfen county, Shanxi Province, China, causing 277 deaths, 4 missings, and 33 injuries (Li and Coop, 2018). On January 25th 2019, the tailings dam of the Brumadinho mine that was operated by Vale S/A failed catastrophically, the number of deaths stands at 259, with 11 still missing, by January 2020 (Lumbroso et al., 2020). With the further development of society, the demand for ore continues to increase. At present, thousands of tailings dams around the world contain billions of tons of waste from mineral processing activities in mine production and operations (Azam and Li, 2010). The safety of tailings dam has been widely concerned by all circles of society. Many studies on the permeability characteristics of tailings have been conducted, and most of them have not considered the influence of particle size on the permeability characteristics. Ou et al. (2001) explored the relationship between tailings permeability coefficient and buried depth by establishing the relationship between overburden soil pressure, permeability coefficient and pore ratio. Guo et al. (2009) used a constant grid simulation analysis method to reduce the permeability coefficient of the dry zone to deal with the virtual flow above the saturated surface, and obtained a three-dimensional seepage mathematical model of the tailings dam that is more close to the actual situation. The seepage field, the saturation line and seepage quantity were inversely analyzed. Hu et al. (2012) analyzed the relationship between voltage and permeability coefficient of tailings in the electric field based on varying-head, the column leaching experiment, and found that the system has a better permeability after power turn-off compared to those which have not received the effect of electric field.

ABSTRACT: Matrix acidizing is widely used to stimulate carbonate reservoirs with low permeability. The two-scale continuum model is mainly employed to simulate the large-scale continuous dissolution of solid matrix by the acid solution due to the high model accuracy and low calculation expense. The classical two-scale continuum model considers the hydrological-chemical processes during the matrix acidizing. But for the actual stimulation process, the chemical reaction between acid solution and solid matrix constantly releases the reaction heat. Moreover, the mechanical stability of wormhole structures also changes with the constant simplification of solid pore structures. Hence, a comprehensive mathematical model is still needed to take into account the various mechanisms of the acidizing process. In this work, the classical two-scale continuum model is further extended to consider couple effects of thermal-hydrological-mechanical-chemical processes on the acidizing results. Energy conservation equation and solid mechanics equation are added to monitor the energy variation and wormhole stability in the acidizing system. Based on this improved model, a comparative parameter study is performed to study the effect of different process parameters on matrix acidizing results. The results show that an optimum value exists for the acid injection rate, at which acid consumes the least to achieve breakthrough and wormhole dissolution pattern forms. Increasing the acid concentration or reducing the acid diffusion coefficient can effectively reduce the amount of acid consumed to achieve a breakthrough. The effect of reaction temperature on acidizing is obvious when the injection rate is relatively high. Besides, the optimal acid injection rate decreases as the activation energy increases or the acid diffusion coefficient decreases. The compressive stress load on the core sample reaches its maximum value at the beginning of acidizing stimulation. When the acid injection rate is very high, the core's maximum compressive stress load can exceed the compressive strength. It should be noted that the improved two-scale continuum model used in this study currently only monitors the mechanical stability of wormholes. More work will be done on wormhole mechanical damage development in the near future.

ABSTRACT: Several modified methods of hydraulic fracturing have been published in the recent literature. The ultimate objective of modifying conventional injection hydraulic fracturing techniques is to increase the damage zone around hydraulic fracture, thereby increasing the conductive pathways to enhance reservoir deliverability. In this paper, we present a laboratory-scale example of the new concept of cyclic injection hydraulic fracturing to help reduce fracture breakdown pressure (FBP) and maximize stimulated reservoir area. It is hypothesized that the repetitive changes in stress and failure of asperities during cyclic injection stimulation enhances the fracture damage zone, and results in multitude of secondary fractures around the main hydraulic fracture, thereby increasing the total reservoir contact surface area. To test this hypothesis, a series of hydraulic fracturing experiments are conducted on dry Tennessee sandstone samples under triaxial stress condition ( σ V = 1500 psi, σ H = 3000 psi and σ h = 500 psi). Three types of cyclic injection protocols are experimentally investigated: (i) Pre-breakdown cyclic injection fracturing where fluid is injected in cyclic manner till breakdown, (ii) Post-breakdown cyclic injection which involves injection of fluid in cyclic fashion after rock breakdown, and (iii) Pre-post breakdown cyclic injection in which injection fluid is cycled both prior to and after the rock failure. Real-time acoustic emissions (AE) were monitored and post-failure, fracture permeability was measured. SEM statistical analysis of the fracture process zone was done on core plugs extracted adjacent to the main fracture. Fracture permeability and the number of pre-breakdown AE were used as main metrics to compare performance of cyclic injection stimulation with monotonic injection. Our test results show that the pre-breakdown cyclic injection fracturing reduces the FBP by as much as 60% compared to the monotonic injection pressure and enhances the fracture permeability by a factor of 2-to-6 even at 5000 psi confining pressure. SEM statistical analysis of the fracture network shows that the width of fracture process zone around the primary fracture is enhanced by a factor of 2.5 in pre-post breakdown cyclic injection fracturing. Our results provide laboratory-scale evidence of the concept of cyclic injection hydraulic fracturing in tight rocks and shows potential to make field completions more efficient.

ABSTRACT: Physical properties of rock fractures are influenced by stress and geometric factors. The ability to describe the structure of fractures is of significance to subsurface engineering. Owing to the relative roughness of rock surfaces, the distribution of fracture openings fundamentally controls both the conductivity and elastic responses of the medium. Implicitly, the stress-dependent fracture aperture height distribution links flow properties to elasticity. A comprehensive understanding on the connections among fracture aperture distribution, stress conditions and flow-elastic properties thus forms an applicable basis for medium characterization. We propose a method to characterize fracture apertures with their stress-dependent flow-elastic relations. The dependencies of various flow and elastic properties in single rough fracture hosting rock, on aperture distribution and normal stress levels are first investigated. Statistical roughness parameters, which capture the spatial correlation and overall height variation of first-contact fracture apertures are adopted for the description. Apertures in rough fracture are numerically generated and their flow and elastic properties under static compressions are simulated. We examine the permeability and resistivity as indicators for flow properties, and elastic wave velocities for elastic properties, respectively. The geometric sensitivity of the respective stress-dependent flow, elastic properties, as well as their joint relations are then extracted. From that we obtain insights on the differentiating power of fracture roughness parameters from these relations. Subsequently, we present a workflow for characterizing fracture apertures with permeability and velocities and illustrated the application with a case study. Measurements are made on an artificial single-fractured granite core and simulation results on various synthetic apertures under the same modelling framework are incorporated. By pursuing for consistent permeability-velocity relations against stress, we invert for a potential range of roughness parameters for the target fracture. Results obtained are in close agreement with actual measured statistics. 1. Introduction From hydrocarbon production, geothermal energy extraction, ground water flow, carbon sequestration to nuclear waste disposal, characterization of fractured medium plays a critical role in design and risk assessment of subsurface engineering activities. Alongside with lithological factors, the physical properties of fractured rocks are controlled by their internal geometries. For single fractures, the implicit linkages between fracture flow and elastic responses via their aperture distribution has been conceptualized (Pyrak-Nolte and Morris, 2000). For instance, the connected fracture apertures provide percolation passage for fluid transports. Responses of which are dictated by the size and spatial variability of apertures (Li et al., 2008; Ma et al., 2019). The rock asperities in contact and stressfree surfaces controls the static and dynamic stiffness of the fractured rocks (Swan, 1983; Choi et al., 2014). These properties evolve distinctively under stressing on fracture for different aperture distributions. A thorough understanding on aperture and stress dependency of fracture flow characteristics and elasticity properties enables the prediction of fracture properties from geometric characteristics and stress conditions. With that, inter-property interpretations (Brown and Fang, 2012; Ma et al., 2018; Al-Dughaimi et al., 2020) as well as formulation of inverse problems (Ma et al., 2020a) could be enabled. It eventually provides an opportunity for integrating the flow and the seismic data for the purpose of field scale fracture characterization (Kang et al., 2016).

ABSTRACT: The depleted shale reservoirs have shown promising potentials for permanent geological CO 2 storage (GCS) either as a caprock or as reservoir storage units. In this study, we experimentally investigated the impact of localized biogeomechanical process on geological CO 2 storage in a depleted heterogeneous reservoir, using subsurface samples from Wolfcamp shale formation and a microbial strain. We first obtained the mechanical properties of shale samples using the scratch test method, in addition to the measurement of their initial porosity and permeability. We treated the shale core samples with a bacteria strain at distinct conditions. Further, we obtain the post-treatment mechanical properties and the new porosity and permeability measurements of the microbially-treated shale samples. Finally, we analyzed the effect of the modified properties on long-term CO 2 storage in the Wolfcamp shale formation. Our results indicated that in depleted Wolfcamp shale reservoirs, microbially-altered properties could decrease the porosity, and enhance long-term caprock integrity and the security of stored CO 2 . 1 Introduction Biogeomechanics is the scientific study of how biological processes influence the mechanical properties and behavior of rock and soil (Kolawole et al., 2021). Few studies have attempted to investigate the effect of biological processes on the geochemical (Abdel Aal et al., 2004; Atekwana et al., 2006), physical and mechanical properties of unconsolidated sandstones (Kalish et al., 1964; Phillips et al., 2015; Hudyma et al., 2018), carbonates (Raleigh and Flock, 1965), and minerals (Mueller and Défago, 2006). The bacterium Sporosarcina pasteurii (ATCC® 11859 ™ ) (Yoon et al., 2001), also known as Bacillus pasteurii , was utilized for this study. The bacterium Sporosarcina pasteurii , was observed to rapidly precipitate calcite in sand columns as the bacteria growth increases, for selective cementation and plugging of porous media (Stocks-Fischer et al., 1999). Shale reservoirs, with ultra-low permeability, require reservoir-stimulation techniques to inject or extract fluids from the shale reservoirs (Jia et al., 2019; Schwartz et al., 2019; Kolawole et al., 2020; Kolawole and Ispas, 2020a). The clay particle orientation, heterogenous layering, and microfissures are causes of high anisotropy in shale rocks (Hornby et al., 1993). Studies have shown that shale reservoirs have promising potentials for permanent geological CO 2 storage (GCS) (Kang et al., 2011; Aljamaan et al., 2017; Kim et al., 2017; Azenkeng et al., 2020; Goodman et al., 2020).

ABSTRACT: Unconventional Shale reservoirs, with typically ultra-low permeabilities, have been a major focus of hydrocarbon production over the past few decades. In this paper, we investigated the effect of biogeomechanical altered near-wellbore properties on hydrocarbon recovery from tight formations, using Niobrara shale samples. We first obtained the mechanical and elastic properties of Niobrara shale samples using the scratch test method. Subsequently, we treated the core sample with a cultured microbial solution at distinct conditions. Further, we obtained the new geomechanical properties impacted by the process. Finally, we showed the potential impact of this altered near-wellbore properties on hydrocarbon recovery from the Niobrara shale formation. Our results suggest that in Niobrara shale reservoirs, biogeomechanical alterations of near-wellbore properties could potentially (1.) impact the mechanical, microstructural and mineralogical properties, (2.) reduce its mechanical integrity, and (3.) improve hydrocarbon recovery from Niobrara shales in addition to other stimulation techniques. 1 Introduction Biogeomechanics is the scientific study of how biological processes influence the mechanical properties and behavior of rock and soil (Kolawole et al., 2021). Few studies have attempted to investigate the effect of biological processes on the geochemical (Abdel Aal et al., 2004; Atekwana et al., 2006), physical and mechanical properties of unconsolidated sandstones (Kalish et al., 1964; Phillips et al., 2015; Hudyma et al., 2018), carbonates (Raleigh and Flock, 1965), and minerals (Mueller and Défago, 2006). The bacterium Clostridium acetobutylicum (ATCC® 824 ™ ) (Sreekumar et al., 2015) is utilized for this study, and it is also known as "Weizmann Organism". In a research study (Banat, 1995), molasses were injected together with Clostridium acetobutylicum into sandstone rock samples, the metabolism action of the bacteria increased the reservoir permeability, and hence significantly improved oil recovery. In a microbial enhanced oil recovery (MEOR) study (Van Hamme et al., 2003), the in-situ growth and metabolism action of Clostridium acetobutylicum reduced the interfacial tension and increased microscopic oil-displacement efficiency, hence improving hydrocarbon recovery. The study further established that the synthesis of organic acid metabolite by Clostridium species dissolves the minerals-grain bond (cementation) in reservoir rocks, and increases pressure and permeability.

ABSTRACT: Natural fracture shear slip can induce an immediate increase in permeability. This permeability increase is the goal of shear stimulation via fluid injection. However, shear slip could breach caprock seals that are key to containing fluids in the subsurface and this slip can be seismic, causing damage to buildings and infrastructure. To predict the effect of slip on subsurface flow and transport, models require relationships that link fracture properties to porosity and permeability. Here, we combine measurements and theory to provide empirical relationships that could enable predictive estimation of fracture permeability after slip. The proposed relations link fracture length, shear displacement, fracture apertures, hydraulic apertures, and fracture permeability. We consider both fracture creation and the re-activation of existing fractures that have been infilled by minerals. Our hope is that these relationships are useful to the community to ensure safer and more successful subsurface fluid injection and production operations. 1. Introduction Shear fractures in the subsurface can dominate fluid flow by more than six orders of magnitude higher permeability than the adjacent rock matrix (Frash et al., 2017). These natural fractures are a challenge to characterize in-situ (National Research Council, 1996) and are subject to time-dependent processes (Meneffee et al., 2020) and stress-dependent processes (Bandis et al., 1983). Fluid injection can increase pore pressure to stimulate fractures by shear slip. This helps to increase the accessed reservoir volume for oil and gas production (McClure and Horne, 2013) or to interconnect wells for enhanced geothermal energy production (Tester et al., 2006). However, shear slip also brings the risk of induced seismicity (Ellsworth, 2013). A relationship is needed to predict the possible range of fracture permeability and the nominal values of permeability for subsurface flow and transport modelling. Numerous lab studies have investigated the mechanical and hydraulic properties of shear fractures (Witherspoon et al., 1980; Bauer et al., 2016; Ye and Ghassemi, 2018; Frash et al., 2019a; Proctor et al., 2019; Li et al., 2020). Many of these studies preferred saw-cut rock specimens to improve experiment control and data interpretation. However, the small variances that are typically observed for smooth fractures do not adequately reflect the six or more orders of magnitude variability of permeability that is observed for natural fractures and fractures in the field. It has become crucial to capture the fuller uncertainty of natural fracture properties in predictive flow models in order to provide confidence in the safety of future field developments and the success of stimulation designs.

ABSTRACT: Influenced by the gravels, hydraulic fractures in the conglomerate reservoir will circumvent gravels and form partially curved fracture surfaces, which hinders the flow of fracturing fluid and the migration of the proppant, and is adverse to the well production of conglomerate reservoirs. This paper mainly studies the way the hydraulic fractures to cross gravels by laboratory hydraulic pulse fracturing experiments. The self-developed hydraulic fracturing experiments platform can provide tri-axial stresses up to 50MPa, the cell temperature of 180° and a pulse peak pressure of 70MPa. The size of the conglomerate specimens is 300×300×300mm 3 , and the simulated formation stresses are 25MPa,30MPa and 32MPa. The specimens are cut to observe the hydraulic fractures and induced fractures around the gravels after the experiment. Studies have shown that: (1). Hydraulic pulse fracturing, imposing the dynamic loading on conglomerate specimens, reduce hydraulic fractures that circumvent gravels in conglomerate reservoir, while the hydraulic fractures tend to cross gravels and form straight hydraulic fractures. (2). The pulse peak pressure (50MPa) affects whether hydraulic fractures cross the gravels in the conglomerate reservoir. 1. Introduction In China, conglomerate reservoirs are widely distributed in Mesozoic and Cenozoic continental petroliferous basins in the east and west of China. For example, Mobei Oilfield and Karamay Oilfield in Junggar Basin of Xinjiang, Kuqa Depression in Tarim Basin, Manite Depression in Erlian Basin, Biyang Depression in Nanxiang Basin, and Jiyang Depression in Bohai Bay Basin (T.T. Hu et al.,2021, Z. W. Zhu et al.,2021). With the exploration of oil and gas, the conglomerate reservoir has become one of the important targets in the future (H. Zhang et al.,2021). As shown in figure 1, due to the large amount of high-strength gravels in the conglomerate, the fracture path will be affected by the gravels in the conventional hydraulic fracturing process, and the fracture will often bypass the gravels, which partly impedes proppant migration and fails to achieve the expected stimulation effect (W.Y. Lv et al.,2021).

ABSTRACT: The application of flow and heat transfer through porous media is widely spread in many scientific and engineering fields. In this paper, we combine Lattice Boltzmann Method (LBM) with finite difference method to simulate the process of flow and heat transfer in random porous medium based on pore scale. The 2D geometric models of pore structure with different structural characteristics were generated by the quartet structure generation set (QSGS) and the generation algorithm of random granular porous media. The numerical simulation is conducted to investigate the effects of pressure drop, porosity and pore structure on fluid flow and heat transfer in porous media. The detailed distribution of velocity and temperature in complex pore space was obtained and presented visually. The results show that the increase of pressure drop will enhance the fluid transmission rate and heat transfer rate in porous media; due to the random distribution of pore structure, there is no obvious law between the flow and heat transfer rate and porosity in porous media; the complexity of pore structure leads to the complexity of the flow and heat transfer mechanism in porous media. The numerical method established in this work provides a promising approach to study pore-scale flow and heat transfer in complex porous structures. 1. Introduction Porous media exist widely in nature, such as rock, soil, sponge, blood vessel, foam metal, etc. The pores of most porous media are non-uniform distribution, with strong randomness and the pore size ranges from nanometer to millimeter. Therefore, the characteristics of flow and heat transfer through porous media are very complex, which are affected not only by the physical parameters such as fluid density, viscosity, thermal conductivity and dynamic parameters such as fluid pressure and temperature, but also by the geometric parameters such as pore size and distribution.

ABSTRACT: It is widely accepted that massive deployment of Carbon Capture and Storage (CCS) in geologic media at the gigatonne scale should be part of the mitigating pathways toward net-zero CO 2 emissions. For a successful geologic CO 2 storage, the caprock sealing capacity and the associated governing processes have to be assessed in detail. In this contribution, we aim at improving our understanding of hydromechanical processes induced by dynamics of CO 2 leakage through intact shaly caprocks. To this end, we perform laboratory experiments on supercritical CO 2 injection into a caprock sample under representative subsurface conditions. We numerically simulate the process to provide a mechanistic interpretation of experimental observations. Overall, we find that CO 2 intrusion into the pore network increases pore pressure and triggers hydromechanical coupling effects, mainly causing the specimen to expand after an initial transient compaction. The pressure-induced rock expansion slightly enhances the porosity and permeability, promoting CO 2 flow close to the upstream. However, the high entry pressure and ultra-low effective permeability of the non-wetting phase limit the bulk volumetric penetration of CO 2 deep into the caprock. Therefore, advective flow of CO 2 is restricted to the lowermost portion of intact caprock, whereas diffusion extends along the whole caprock sample. 1. Introduction Proposed mitigation pathways to reach net-zero carbon, relying on the best available science and technologies, involve capturing significant amounts of CO 2 from the atmosphere and large stationary sources and injecting them into the subsurface through a process known as geologic carbon storage (Celia, 2017; IPCC, 2018). Target injection formations are usually deep enough to bring CO 2 to its supercritical state, i.e., pressure>7.38 MPa and temperature>31.04 °C. In a supercritical state, CO 2 has a liquid-like density, ensuring high hydrodynamic storage capacities, and gas-like viscosity, enhancing injectivity. However, CO 2 density never exceeds that of resident brine at temperature and pressure conditions of sedimentary formations. Injected CO 2 is thus buoyant and flows upward. As a result, the CO 2 plume preferentially propagates at the top of the reservoir along the caprock interface, imposing a potential risk of CO 2 leakage through the caprock (Rutqvist and Tsang, 2002). Suitable host formations should be overlain by a low-permeability and highcapillary entry pressure caprock that prevents buoyant CO 2 migration and keeps it permanently stored (Bachu, 2003; IEAGHG, 2011). Reliable assessment of the caprock sealing capacity and controlling parameters is of paramount importance from a site selection point of view but also to the public perception of worldwide geologic carbon storage at the gigatonne scale.

ABSTRACT: A reliable sanding prediction is required for field development decisions including well construction and facility design and the overall field's economics assessments. This paper shows an example from a gas field in Western Australia at its early development stages. A field-specific 1D geomechanical model calibrated with field stress measurements and drilling data, well logs and core tests is used to assess the risk of sand production for field life duration for both existing and future wells. The field geomechanical model revealed subtle variations from the regional stress regime with significant implications for sanding tendency and sand management strategies. An initial evaluation using a non-calibrated stress model indicated low sanding risks. However, the revised study calibrated with well tests and productions indicated considerable sanding risks within first few years of production. The sanding risk and sand volume rate is expected to increase with further depletion potentially requiring well intervention for existing producers and active sand control for newly drilled and cased and perforated wells. The analysis also indicated negligible field life sanding risk for vertical and low-angle open hole wells. A combination of passive surface handling and downhole sand control methods are considered using the well-specific sanding risk as a guide. Existing producers are monitored for sand production using acoustic detectors and future wells will have sand catchers to ensure sand production is monitored, quantified, and managed. Vertical and low-angle wells with open hole completion with sand screens are being planned for the upcoming development campaign. 1. Introduction Sand production prediction is essential from the early stages of field development planning for completion design and later for production management. Unconsolidated and weakly consolidated sandstones are prone to fail at low flowing bottom hole pressures during hydrocarbon production. To predict the critical flowing bottom hole pressure for a safe (sand-free) drawdown, a geomechanical sanding model that integrates in-situ stresses, rock mechanical properties, well trajectory, reservoir pressure, production plan and depletion trend is required.

ABSTRACT: During the hydraulic fracturing process, the fracturing fluids can infiltrate into the shale porous matrix surrounding the fractures by spontaneous imbibition. However, the pores in shale oil reservoirs mainly range from 2 to 200 nm. For the nanoscale pore network, the fluid-solid (water-wall and oil-wall) molecular interactions, which can result in the nanoscale effects of the boundary slip and the varying interfacial fluid viscosity, will make the fluid flow behaviors more complex and difficult to characterize. Additionally, the change in pore size due to the stress sensitivity could consequently affect the imbibition processes. In this work, we firstly establish a new generalized imbibition length model in shale nanopores and nanoporous matrix by considering the effects of pore dimensions, tortuosity, nanoscale effects and stress sensitivity. Further, based on the imbibition model, the enhancement factor model is conducted to characterize the nanoscale effects on the imbibition capacity. Finally, the influence of the multi-mechanisms on the imbibition volume and enhancement factor is discussed. Based on discussions, this study can provide microscopic basics into water imbibing into nanopores and nanoporous matrix, and provide basic theoretical models for some pore-scale simulations, such as pore network models, etc. 1. Introduction Shale oil is currently one of the most important unconventional resources in petroleum exploitation, and due to the production of horizontal drilling and multistage fracturing, it can be effectively and economically explored (Hongjun et al., 2016). During the hydraulic fracturing process, the fracturing fluids can be imbibed into the porous matrix surrounding the fracture surface by spontaneous imbibition, as shown in Fig. 1, and it has a great effect on the enhanced shale oil recovery and the formation damage (Li et al., 2019). In shale reservoirs, the pore size is nanoscale, which mainly ranges 2 nm–200 nm (Saraji and Piri, 2015; Yuan et al., 2017). For the nanoscale pore network, the fluid-solid (water-wall and oil-wall) molecular interactions, which can result in the nanoscale effects of the boundary slip and the varying interfacial fluid viscosity, will make the fluid flow behaviors more complicated and difficult to characterize (Wang et al., 2019a; Wu et al., 2017). Additionally, the change in pore size due to the stress sensitivity could consequently affect the imbibition processes (Shen et al., 2017; Sheng et al., 2018). Therefore, clarifying the imbibition of fracturing fluids into the nanoporous matrix considering the nanoscale and compressibility effects is essential for the enhanced shale oil recovery, and there are few researches about that.

Abstract The objective of this study is to develop a predictive model for induced seismicity in Azle, North Texas using one-way coupled fluid flow and geomechanical simulations. The simulation results were compared with observed earthquakes to quantitatively assess potential seismicity in the area, given operating conditions of produced water disposal and hydrocarbon production. The detailed fault modeling was realized by representing the faults as discontinuous surfaces in the geomechanical simulation model and incorporating seismic interpretation of the faults. The flow model was first calibrated by history matching well responses. The calibrated pressure distributions were updated into the geomechanical simulation model to assess fault slips and resulting fault frictional energy. We utilized the alternating conditional expectation (ACE) algorithm to build a correlation between the incremental frictional energy and observed earthquakes with the magnitude larger than 1.5. The calibrated simulation results suggested that the poroelastic effect was the driving mechanism of the earthquakes in the basement. The ACE algorithm found the maximum correlation between the energy and the earthquake frequency and suggested that frequent earthquakes are not expected with current operating conditions. Introduction The Azle area, the area of interest in this study, experienced a series of earthquakes between late 2013 and early 2014 with the maximum magnitude larger than Mw3. Previous two site-specific studies utilized numerical simulations to understand the mechanism of the Azle earthquakes incorporating 70 gas producers and two injectors in the Barnett and the Ellenburger, respectively. Hornbach et al., 2015 built a single-phase flow model and found that with different parameter combinations, it is possible that pore pressure at the fault could exceed up to 0.14MPa. They found the pressure increase could propagate to the basement through highly conductive fault and lead to sufficient reduction in the effective normal stress to reactivate a critically-stressed fault (Reasenberg and Simpson, 1992; Stein, 1999). Based on the detailed review of the area and provided data by Hornbach et al., 2015, Chen et al., 2020 investigated the Azle area using coupled fluid flow and geomechanical simulations including the entire computational domain, from the overburden to the basement, to investigate actual stress and pressure change in the basement. The model was calibrated integrating injectors’ bottom-hole pressure (BHP) and earthquake magnitude and showed that sufficient plastic strain can be accumulated in the basement compared to the observed earthquakes without direct fluid interaction in the basement. The deformation in the basement was mainly owing to the poroelastic effect caused by unbalanced loading in the reservoir where injection and production is mainly dominant in northwest and southeast across the faults, respectively.

ABSTRACT: Analysis of nano-scale transport processes between pores in shale and fracture systems is essential for predicting hydrocarbon production. Accurate estimation of total hydrocarbon storage is important in reservoir management, economically and financially. Also improving EOR in unconventional reservoir requires comprehensive knowledge of the rock characteristics, such as pore size distribution. In this work we presented the results of digital rock analysis (DRA) for high-resolution micro-CT and FIB-SEM images of Bakken core plugs. The workflow includes a fundamental digital rock physics procedure to estimate porosity and absolute permeability and compare the pore-scale heterogeneities in different core samples. From the analyses that is evident that permeability can vary in even short distances of sampling in an unconventional play, such as the Bakken Fm. Therefore, assuming an average permeability for such formation may not be a promising assumption, rather upscaling techniques are recommended. Better understanding of heterogeneity in shale plays can help us to design optimal EOR operations for improved recovery. 1. Introduction Nowadays, possessing massive oil reserves with great potential of oil production is well known for unconventional reservoirs, which have a huge effect on the future of the petroleum industry. In the United States, reservoirs such as the Barnett, Woodford, Haynesville, Fayetteville, Marcellus, and Eagle Ford Shale are examples of these types of reservoirs (Chen et al, 2013). However, the complex characteristics of these reservoirs (i.e. ultra-low permeability and heterogeneity) cause the ultimate recovery factor to remain low (less than 10%). Numerous researchers have shown that nano/micro-scale heterogeneity has noticeable impact on larger scale properties, physical phenomena, and hydrocarbon recovery assessment. Therefore, it is essential to determine the microstructure information (Farajzadeh et al., 2011). In specific cases, one of the prevalent methods for enhancing oil recovery lies within CO 2 injection and huff and puff. These methods have gained the attention of researchers and have showed great recovery enhancement during both experimental and field results. This mainly happens due to low MMP (Minimum Miscibility Pressure) with oil, and small molecule size when compared to other common injected gases. Hence, obtaining internal parameters such as porosity, specific surface area, and pore size distribution is necessary to analyze the nano-scale transport processes between pores in shale and fracture systems (Chen et al., 2013). Consequently, accurate estimation of total hydrocarbon storage will improve reservoir management, economically and financially. Among all input parameters to reservoir simulation, absolute permeability is counted as an essential one to forecast hydrocarbon production. This gets even bolder when dealing with heterogeneous reservoirs, where permeability values reach nano-Darcy.

ABSTRACT: Application of uniaxial strain boundary condition as stress path to measure mechanical and petrophysical properties is critical in estimation of reservoir compaction/ subsidence, estimation of recoverable resource via compaction drive, change in reservoir producibility and finally, to calibrate 4D seismic. The drop in demand in hydrocarbon resources, coupled with operating at low-price environment will continue to constrain laboratory measurement. This warrants for optimally utilizing the available core material and acquire of multiple datasets from limited material and testing occurrence. However, the available space inside a typical rock mechanics cell is limited, as radial deformation transducer, a key to establish uniaxial strain boundary condition, need to be placed at the center of the sample. This paper reports results of an experimental study aimed at finding a viable alternative that permits maintaining uniaxial strain boundary condition without using radial deformation transducer. The amount of pore fluid expelled/injected during simulated depletion/re-injection sequence is studied and its applicability to replicate uniaxial strain condition is explored. Results indicate that the change in porosity, uniaxial compaction and pore volume compressibility coefficient measured using the new technique show excellent agreement with that measured utilizing conventional method, i.e., radial deformation transducer. In addition, the measured variation in sample diameter is found to be well within the acceptable limit of experimental error. 1. Introduction Knowledge of insitu stress and pore pressure and how they change during the geological and production time scale is a topic of interest for decades. Stress and pore pressure change during hydrocarbon extraction and resulting rock deformation has consequences that can be tied back to a dollar value because of lost time and/or lost production. Understanding of geomechanical and petrophysical properties of reservoirs that are soon to be exploited or already producing thus warrants for in-depth characterization effort. Although interpretation of geophysical data takes a significant share of these efforts, direct measurement performed on core materials extracted from subsurface always plays a key role. However, obtaining whole core for every new development/ project can be costly and requires time. Optimum utilization of core material is hence more important than ever in the current operational environment. One solution to this problem is acquiring sidewall plugs and conducting measurements (Mitra et al., 2016; Govindarajan et al., 2019). Another option is obtaining multiple measurements from single experiment while obeying the underlying physics behind the measurements. The latter not only helps optimum utilization of core materials but also allows to integrate and reconcile various geomechanical and petrophysical properties as the uncertainty owing to rock heterogeneity is avoided and the stress path for measurement remains the same. However, realization of such experimental program requires using multiple transducers in a single experiment. This subsequently brings in the challenges of accommodating each of them in the tight annular space inside the test vessel. For example, estimation of permeability change across the sample while maintaining uniaxial strain boundary condition requires strain gauges/radial transducer which in turn interferes with the plumbing used for fluid flow. Another area of concern is testing at high temperature environment, typical for deepwater operation, steam-flood or geothermal wells. At elevated temperature, the performance of radial transducers suffers significantly. Utilizing uniaxial strain stress path at elevated temperature can thus be challenging.

ABSTRACT: Since the flow back process is crucial to post-frac production behavior for shale gas wells in shale gas play, considering setting the fractured well as an injecting well, a numerical model was established to simulate the flow back dynamic by software Eclipse. Then a workflow was put forward to simulate the effect of hydraulic fracturing fluid on flow back of shale gas wells, and main controlling factors affecting flow back rate and production are analyzed. Simulation result demonstrates that gel breaking liquid mainly flow through main fractures, and then in adjacent secondary fractures. The rankings for factors affecting flow back rate is gel breaking liquid, reservoir pressure coefficient, bottom hole pressure and stage. During factors affecting cumulative production, reservoir pressure coefficient is the main controlling factor, then following fracture height geometry, adsorbed gas content, stage, fracture complexity, fracture conductivity, bottom hole pressure, and viscosity of gel breaking liquid. The study is applicable to optimize flow back manner in shale gas wells and enhance the productivity. 1. Introduction Recently, as a kind of clean energy, shale gas has resulted in an energy revolution all over the world. Shale gas reservoirs are characterized by complex lithology, poor matrix permeability, various natural fractures and beddings, and economic production can only be achieved by implementing large-scale horizontal well fracturing technology. The amount of fracturing fluid used in a single horizontal shale gas well is large, generally more than 3×10 4 m 3 , so the flow back process is crucial to postfrac production behavior. However, for flow back progress of fractured shale gas wells, some researches have focused on the gas lift process facilitates, fracturing fluid tracer and proppant tracer to analyze fracturing fluid flow back and inter-well interference (William et al., 2010; George et al., 2010; Cheng et al., 2012; Samarth et al., 2013), and some numerical model studies have not been systematically studied and without consideration of multiple factors (James et al., 2010; Sun et al., 2011; Clarkson et al., 2012; Mu et al., 2012; William et al., 2013).

ABSTRACT: Tight naturally fractured sandstone reservoir plays an important role in modern oil and gas development. However, it suffers from stress sensitivity damage due to well-developed natural fractures. To understand it, this paper introduced transient pressure pulse decay test (PDP), a time-saving and accurate method, to quantitatively evaluate the stress-dependent permeability, using in-situ core samples with different patterns of natural fractures, and the stress sensitivity index was used to describe the level of permeability recovery. As a consequence, the initial permeability of rocks with partially filled fractures are generally higher than that of rocks with filled fractures, because the partially filled material contributes to the flow by restraining compaction. During the loading process, if the fractures have smaller width, the permeability decreases less. During the unloading process, faster recovery rate requires type A rocks with lower inclination of the fractures. Rocks with micro-fractures have permeability hysteresis, which especially happens to rock samples with the narrowest fracture width, resulting in stronger stress sensitivity effect. This work gives insight to estimate stress-dependent permeability with different natural fracture patterns. 1. Introduction Tight sandstone reservoirs with natural fractures tend to develop petroleum resources more efficiently and have a favorable prospect especially in the process of the hydraulic fracturing treatment. However, due to low porosity, low permeability, and well-developed natural fractures, tight sandstone reservoirs have strong stress-dependent damage caused by the decreases of formation pressure in the later stage of reservoir stimulation, which can reduce the reservoir permeability and then oil and gas production drops dramatically (Zhang et al., 2019). In the fracturing process, it is inevitable to squeeze the matrix, and such extrusion will lead to an increase in formation pressure. With the mutual influences of overburden pressure increment and porosity pressure decrement, the net pressure increases, leading to the permeability damage, which will negatively change the flow dynamics of the fluids in porous media. This kind of damage is also known as stress sensitivity effect.

ABSTRACT: Quantitative characterization of the effect of geomechanical coupling on solute transport and permeability evolution in fractured rocks is an open problem in geologic carbon sequestration, groundwater contaminant remediation, enhanced oil recovery, and tracer-based reservoir surveillance. Despite recent advances in modeling flow and geomechanics coupling, a holistic approach to capturing the synergy between fluid flow, solute transport, induced stresses, and fracture mechanics is lacking. This study investigates the rich interplay between these processes by proposing a novel computational framework to solve the coupled flow, transport, geomechanics, and fracture mechanics problem. Embedded Discrete Fracture Modeling (EDFM) is used to model the flow and transport processes in fractured porous media while an improved Bandis model is employed to capture the fracture-mechanical response to flow-induced stress perturbations. The role of transport-geomechanics coupling in modulating the spreading and miscibility of a solute slug during viscously unstable flows is examined. We examine how flow-transport coupling, parameterized through the solute viscosity contrast and the fracture permeability, influences the stress state and fracture stability in the domain. A case study, inspired by a huff-n-puff tracer flowback study, is conducted to investigate the applicability of the proposed framework in the field. A sensitivity analysis is performed to evaluate the dependence of global transport characteristics, permeability evolution, and fracture stability on parameters dictating the strength of coupling between geomechanics, flow, and transport. 1. Introduction Applications of fluid injection into naturally or hydraulically fractured reservoirs are evident in many engineering disciplines: carbon sequestration (Iding and Ringrose, 2010), contaminant tracking (Sahimi, 2011), tracer surveillance (Warner et al., 2014), and enhanced oil recovery (EOR) (Jimenez et al., 2016). In those practical scenarios, it is important to characterize how well the injectant mixes with the in-situ fluid and the spatial coverage of the resultant mixing zone. This is critical in dictating the success of the injection operation, i.e. delivering costly injectant to sweet spots to attain optimal miscibility (EOR), ensuring permanence and security of storage/disposal (carbon sequestration), or tracking the spatial and temporal distributions of tracer particles (contaminant tracking). The geologic formations are often geomechanically sensitive because of the presence of discontinuities (i.e. joints, faults, or fractures) and the heterogeneity in consolidation environment. Therefore, there is a need to integrate geomechanical coupling in transport modeling to examine the extent of impact of stress-activated processes on macroscopic transport metrics (Tran and Jha, 2018).