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 Pore pressure prediction in shales undergoing compaction, including both mechanical and chemical processes, is customarily related to the mechanism referred to disequilibrium compaction. However, even when this mechanism is established and the normal compaction trend in sonic velocity, as a proxy for shale porosity, is well constrained, the pore pressure prediction may be in error because of the lithological variation in shale composition. Presence of solid organic matter in excess amounts in shale formations that have never been exposed to the pressure-temperature conditions in the oil window is an example of these lithological effects, causing marked overprediction of pore pressure even in thermally immature mudrocks. This necessitates implementation of bulk density and sonic velocity log corrections in organic-rich shales prior to performing standard pore pressure prediction workflows. In this paper it is shown how these corrections can be made and the outcomes of the pore pressure prediction can be dramatically improved by using combination of rock physics models relating bulk density to total organic carbon (TOC) and P-wave velocity to bulk density in organic-rich and conventional shales, respectively. Introduction Pore pressure prediction (PPP) in conventional shales is based on the assumption there is a relationship between the porosity of the shale and the effective stress. The relationship between effective stress and pore pressure is known as Terzaghi's principle (Terzaghi, 1943). The main assumption in PPP is that the porosity of a shale is captured by wireline data, where a reduction or even stabilization in log response is assumed to reflect shale porosity deviation from the normal compaction process, giving rise to overpressure development (e.g., Foster & Whalen, 1966; Eaton, 1975). It is this variation in wireline log magnitude in shales which is used to predict the pore pressure using industry standard models. However, there are several factors that affect the magnitude of the log response within a shale beyond compaction-related porosity reduction, e.g., cementation, different fractions of non-clay material, variation in clay content, and the presence of organic matter. The main goal of this study is to present a method by which variation in the amount of organic matter (Total Organic Carbon; TOC) can be taken into account such that erroneous predictions of pore pressure are avoided. Correcting for TOC is of critical importance as the effect of increasing TOC within a shale leads to a reduction in the magnitude of the log response (e.g., density and sonic velocity) which mimics an increase in pore pressure that may not be actually present in thermally immature shale or organic matter-rich mudrocks undergoing incipient oil/bitumen generation. Erroneous prediction of elevated pore pressure will lead to false magnitudes of the fracture gradient, horizontal stresses, and wellbore stability curves leading to changes in well design that may be unnecessary.

ABSTRACT: Gas wells drilled through coal seams may be influenced by underground coal mining, especially longwall mining. To evaluate the stability of gas wells in longwall chain pillars, NIOSH has developed numerical models to calculate longwall-induced ground pressure, subsurface movements, and stresses and deformations in gas well casings. In this study, FLAC3D modeling was used to model the test gas wells drilled in the chain pillars in a longwall mine under shallow depth. Site-specific geological and mining conditions were used to set up the models and compared the modeling results with the actual measurements of pillar pressure, surface subsidence, and casing deformations. The study shows that the developed model provides reasonably accurate prediction of longwall-induced stresses and deformations in both the overburden over chain pillars and the gas well casings. The study indicates that the longwall-induced horizontal movements are dependent on the depth of cover and overburden geology and concentrate along strong-to-weak rock interfaces. The study also shows that large horizontal displacements are more likely to occur under shallow cover with wet and inclined overburden strata, which may cause shear failure in gas well casings. This study demonstrates that gas well stability in longwall chain pillars can be effectively evaluated using FLAC3D modeling and field measurements. 1. Introduction Gas wells drilled through coal seams can have interaction with underground coal mining, especially longwall mining. Conventional gas wells have long been a problem if present in the vicinity of longwall panels, but they can be plugged if gas well pillars are considered insufficient. Many more safety concerns have been raised for unconventional shale gas wells in longwall coal pillars because gas well damage caused by longwall mining can allow high-pressure gas to leak into the mines potentially causing fire and explosions. In addition, shale gas wells are so costly that it is a huge financial loss if simply plugged. Over the past decade, over 1,500 shale gas wells have been drilled in the current and future reserves of the Pittsburgh coal seam. Influence of longwall mining on these shale gas wells will have to be addressed as future longwall panels are mined. Therefore, it is important to understand how longwall-induced subsurface movements and stresses affect gas well casings and to develop reliable models to assess the stability of shale gas wells.

ABSTRACT: In this study, hydraulic fracturing (HF) operations are re-modelled with discrete fracture network(DFN) approach taking into account natural fractures by input parameters utilized in FracMan software. HF operations are mainly designed by core data from wells. This paper presents that new operation designs are built with DFN according to geomechanical features obtained from outcrop samples of the tight sandstone formation. Comparison of field data and simulation results of DFN model in FracMan are introduced. HF operations are performed in two different wells targeted to tight sandstone formation. Reservoir model is created with data from well logs, core analysis of the wells. Input values used in commercial simulations are also entered as input in DFN model so to be able to compare results of both models. Outcrop samples are extracted from Ordovician aged tight sandstone formation. These samples are exposured to laboratory test to get geomechanical properties such as elasticity modulus, Poisson's ratio. Obtained parameters are utilized as input for DFN simulations. Simulation results created by outcrop samples and field outcomes are also analyzed. By this study, it is expected to decrease field costs and nonproductive time for coring operations in case of results of outcrop samples are alike with data extracted from core analysis. If there is a correlation between outcrop samples and core data, samples could be directly used from surface deposits of the relevant formation. It is highly considered that models created by DFN which enables to create more realistic reservoir and fracture structures reflect more accurate results. 1. Introduction Discontinuities are present to some sort of levels and form on a scale grading from porous medium to continental size in subsurface. These discontinuities with the form of fractures in rock serve as conductors providing preferential pathways for fluid flow with altering aperture, storage capacity, tortuosity and geometry that rule the flow dynamics of fluid system. Snow, 1965 who represented fracture networks with a series of interconnected parallel plates of variable aperture and length first put out this notion of fractured rock. The result is a highly heterogeneous and anisotropic model showing hydraulic behavior which contrasts nobly from homogeneous models.

ABSTRACT: A challenge in CO 2 storage reservoir is how to identify and prevent leakage. The wellbore, used to inject CO 2 , could become a leakage path, for example, through the cement-rock interface. The influence of CO 2 on Draupne shale was investigated first. Shale samples were exposed to CO 2 saturated brine up to one week. The measured elastic moduli show a decreasing trend versus time. This time-dependent modulus was implemented in a user-defined model built into FLAC3D. The features of this model were first tested with a simple geometry. Then wellbore geometry was introduced to study leakage through the cement-rock interface. It was found that with a constant in-situ stress and different annulus pressures (before cementing), the cemented annulus behaved in different manner. The worst scenario could lead the cement-rock interface open and the wellbore lost the integrity. 1. Introduction A challenge in carbon dioxide (CO 2 ) storage reservoirs is to identify and prevent leakage. Wells, used to inject CO 2 , could risk becoming a leakage path if well integrity is lost. CO 2 threatens wellbore integrity when it diffuses into a formation through gaps or cracks in a cemented annulus. Dissolution of CO 2 in formation brine is a trigger of geochemical reactions because of the formation of carbonic acid, see Equation (1) (equation) (1) This reactive fluid acts on specific gradients in the formation rock, hence, affects the geomechanical response. The formation rock referred to in this study is shale, which occupies a large portion along the potential leakage path from the CO 2 reservoir to the surface. A recent review paper by Bhuiyan et al., 2020 has concluded that the interactions between CO 2 and shales occur in different states and scales. Lab tests revealed that Young's modulus decreased when the shale samples were saturated in CO 2 -brine for a longer time (Zhang et al. 2017; Lyu et al. 2018a, b). However, how the CO 2 -brine affects Poisson's ratio was not well studied in the aforementioned works. As observed by Agofack et al., 2019 in a CO 2 injection test, Poisson's ratio shows a measurable reduction.

ABSTRACT: In recent years, large-scale concentrated casing damage occurred in several blocks of the CY oilfield, and the casing damage were concentrated in the oil shale layer where located about 100m above the main producing layer, resulting in a large number of production wells shut-in. The main causes of casing damage are as follows: firstly, it is confirmed that the cohesive force of the interface between mudstone and shale is the lowest through the experimental analysis of the lithological characteristics and mechanical parameters of the oil shale layer, and it is a relatively weak bed; secondly, the proportion of the perfect cementing segment between the reservoir and the maker bed is less than 60% or the length of the good cementing segment is less than 30m, which may cause injected water channeling, or the channel of injected water channeling is formed due to casing string leakage and other engineering reasons, resulting in water inflow and instability of the oil shale;thirdly, when the difference in formation pressure between regions exceeds 0.8Mpa, formation instability will be aggravated, resulting in slip, and shear casing will be damaged to a large extent. In view of these reasons, the countermeasures to prevent casing damage were formulated respectively, such as controlling waterflooding parameters, reducing or blocking water inlet channel, and controlling casing damage situation through a series of preventive measures and strength monitoring. 1. Introduction Since 2009, there has been several concentrated casing damage areas in CY oilfield, and the casing damage ratio of injection and production wells in these areas is higher than 30%, which resulted in the well opening rate lower than 70% and affected the oil producing loss of the block being more than 20%. The casing damage locations are concentrated in the oil shale layer in the upper cap layer of the reservoir, about 100m away from the top of the oil layer, which is a mark layer with stable distribution in Songliao Basin(Du et al.2017 and Zhang et al. 2019). The main types of casing damage are deformation and dislocation with mechanical shear characteristics. Some casing-damaged wells are accompanied by injected water outflow. In order to analyze the cause of casing damage, the paper studied the factors of geology, development, and engineering. By studying the subject, the standards for determining wells at high risks of abnormal injection and water channeling are developed, the wells with high risk of casing damage are further screened out(Hu et al. 1998). Countermeasures to prevent casing damage are particularly formulated for those caused by development and engineering factors(Lu et al. 2019). Through the above work, the occurrence rate of concentrated casing damage can be effectively controlled.

ABSTRACT: Frequent wellbore instability and lost circulation problems were encountered while drilling the first batch of exploration wells in a low-permeability, high pressure and high temperature (HPHT) gas field in the South China Sea, due to very narrow drilling mud weight windows resulting from HPHT reservoir conditions. This study focuses on combining and leveraging geophysical data, rock mechanics testing data, and well-logging data on predicting wellbore instability under HPHT conditions. Full-scale core samples were acquired from HPHT reservoirs of the field, and uniaxial and triaxial rock mechanics tests were conducted to determine the mechanical properties of the rock. The influences of heat transfer between the wellbore and the formation, mechanical properties, in-situ stresses, collapse pressure, and fracture pressure are investigated. Wellbore temperature change induced thermal stress result in an aggravated risk of wellbore instability. Furthermore, the safe mud weight window becomes narrower under the influence of temperature change while it was narrow originally because of the HPHT conditions. A dramatic pore pressure elevation in the reservoir formation leads to an extremely narrow mud weight window less than 0.1 g/cm 3 in this oilfield. 1. Introduction In the petroleum industry, wellbore instability is one of the most common problems in the process of drilling in exploration areas. This is due to the lack of available data and drilling experience. The costs associated with wellbore instability problems account for about 5% to 10% of drilling costs in the exploration and production phase, which means that the global annual costs can reach billions of dollars (Fjaer et al. 2008). Therefore, accurate estimation of safe mud density windows can provide guidance for safe drilling and reduce the cost (Baouchea,2020). In this work, we studied the wellbore instability problem in a low-permeability, high pressure and high temperature (HPHT) gas field in the South China Sea. Frequent wellbore instability and lost circulation incidents were encountered while drilling the first batch of exploration wells in this gas field. These incidents are primarily due to the very narrow drilling mud weight windows resulting from HPHT reservoir conditions. Therefore, this work leverages multiple data, including geophysical data, rock mechanics testing data, and well logging data, to predict wellbore instability under HPHT conditions. The pore pressure, horizontal stresses, collapse pressure, and fracture pressure are estimated, respectively. The prediction results agree with the drilling performances quite well. Furthermore, the safe mud weight window of a planned horizontal production well is designed based on this integrated study.

ABSTRACT: Cement sheath should provide zonal isolation and structural support during the full life cycle of a well. However, achieving long-term cement sheath integrity under complex geological and operational conditions, especially in the high pressure and high temperature shale formation, is still a great challenge. To better understand the long-term failure mechanism of cement sheath, this paper developed a 3D coupled thermal-hydro-mechanical model of the cement sheath system by considering the accumulation of stress-strain state in all stages of the well life cycle using a finite-element method. The model is validated against analytical solutions of the wellbore stress-strain distribution and shows high accuracy. Sensitivity analyses were performed on the variations in pressure, temperature, and anisotropy of deep shale formation. The results show that pressure and the temperature difference between wellbore and formation results in transient flow and thermal diffusion processes with time and the resulting stress change around the well affect the integrity of the cement sheath system. Debonding occurs at the cement-formation interface with a relatively large temperature difference, while the crack tends to heal with a relatively small temperature difference. Besides, a novelty of this modeling approach is that it incorporates the initial stress state in the cement sheath immediately after hardening of the cement slurry, providing more realistic simulation results for considering the accumulation of stress-strain during the full life cycle of wells. The results also indicate that increasing the initial stress of cement sheath is beneficial for reducing the risk of debonding failure of the cement-formation interface. 1 Introduction As the core component of a typical oil/gas well structure, cement sheath provides zonal isolation and structural support to the full life cycle of wells. Failure of cement sheath can lead to a series of wellbore integrity problems, such as sustained casing pressure, blowout, etc. Unfortunately, achieving long-term cement sheath integrity under complex geological and operational conditions is still a great challenge, especially in the deep shale formation which is mainly characterized by high pressure, high temperature, and high horizontal stress difference (GUO Jianchun et al., 2021; HE et al., 2021; ZENG Bo et al., 2020).

ABSTRACT: According to the caving law of thick and hard overlying strata and the evolution characteristics of water-conducting fracture zone, comprehensive analysis of the collapse characteristics of the thick and hard overburden in the fully mechanized caving face, the information on the internal structure of the overburden strata and the development of the "two zones" of the overburden strata after the coal seam in the working face was carried out using methods of similar simulation experiment, microseismic monitoring system, numerical simulation, theoretical analysis and engineering practice combined research methods. Comprehensive analysis of the collapse characteristics of the thick and hard overburden strata in the fully mechanized caving face, the information on the internal structure of the overburden and the development of the "two zones" of the overburden strata after the coal seam in the working face. The results show that: the height of the overburden collapse envelope increases with the advancement of the working face. When fully mined, the collapse height of the overburden is stable, and the height of the water-conducting fracture zone ranges from 100m to 120m. The height is consistent with the overburden collapse envelope. Most of the microseismic events occur near the water-conducting fracture zone, where the energy density is concentrated to form the water-conducting fracture zone. In the numerical simulation, the concentrated distribution area of the fissure field presents a "bridge arch" type of distribution. The fissure development model in the middle of the goaf is higher than the ends of the working face, and the roof rock formation is obviously deformed. When the energy value of the microseismic event reaches 108.708J, a crack will occur, and the crack will gradually penetrate to form a water-conducting fracture zone. Engineering practice verifies that the height range of the water-conducting fissure zone is determined to be 98m-123m. The caving of the thick hard overburden strata and the evolution of the water-conducting fissure zone provide a scientific basis for the prevention and control of water in the working face.

ABSTRACT: The law of salt ion diffusion is an effective means to evaluate the complexity of volume fracture network in shale reservoir. In this paper, a new experimental apparatus for salt ion concentration testing under the conditions of formation temperature and confining pressure was designed. The quantitative evaluation method of salt ion diffusion ability was put forward to evaluate the law of shale salt ion diffusion. The results shown that the salt ion diffusion concentration of shale sample was positively correlated with the imbibition time. The micro-fracture induced by shale hydration increased the area of shale infiltration and ion interaction. The salt ion diffusion concentration was in dynamic equilibrium. The main types of salt ion diffusion were K + , Na + , Cl - and SO4 2- , the higher the complexity of the initial micro-fracture of shale was, the stronger the salt ion diffusion ability was. The hydration of shale can induce new micro-fractures, and its direction was parallel to the direction of shale bedding. Under the experimental conditions, the shortest shut-in time was 15-20 days. The research results play an important guiding role in understanding the interaction mechanism between shale and fracturing fluid. 1. Introduction China is very rich in shale gas resources [1-2], in which the shale gas reservoir of Longmaxi formation in Sichuan Basin is the main development zone [3-7], and the volume fracturing technology of horizontal wells is the key technology for efficient development of tight oil and gas reservoirs [8-11]. The shale reservoir characteristics and fracturing technology are significantly different from those of conventional sandstone reservoirs [12-14]. Shale gas wells shown completely different flowback characteristics after volume fracturing, showing the characteristics of low flowback rate [15-18]. The Eagle Ford basin in the United States is less than 20% less than 50% in the Barnett basin, the flowback rate of Fuling shale gas wells in China is even less than 3% [19-23], and the salinity of the backflow fluid of some shale gas wells in North America is as high as 170000mg/L [24]. The law of shale salt ion diffusion is a key factor affecting the flowback rate of shale gas wells and evaluating the complexity of fracture network and imbibition capacity [25-27], so accurate testing of shale salt ion diffusion law is very important to evaluate the volume fracturing effect of shale gas reservoirs.

ABSTRACT: Longmaxi shale rock is a typical anisotropic rock, the most common used strength criterion is the single plane of weakness (SPW) criterion for wellbore stability analysis of anisotropic formations. However, is this SPW criterion the optimal strength criterion for Longmaxi shale rock? To answer this question, the Longmaxi shale rock was collected from the Silurian formation in Sichuan Basin of China, the specimens were cored with different angles (0°, 15°, 30°, 45°, 60°, 75°, and 90°), then, the triaxial compression tests were conducted. Five most commonly used criteria, such as the SPW criterion, weak plane patch (WPP) criterion, Walsh-Brace (W-B) criterion, McLamore-Gray (ML-G) criterion, and Ramamurthy-Rao (R-R) criterion, were identified to evaluate which one is the optimal strength criterion for Longmaxi shale. The grid search algorithm was used to quickly match the material parameters of anisotropic criteria, the correlation coefficient ( R 2 ) and absolute average relative error ( AARE ) were used as the standard to evaluate the fitting degree of five criteria. The results indicated that the optimal one is the WPP criterion, followed by the W-B criterion, SPW criterion, ML-G criterion, and R-R criterion. The correlation coefficient ( R 2 ) and absolute average relative error ( AARE ) of the WPP criterion are 0.9905 and 5.4477\%. Therefore, the WPP criterion is recommended as the optimal strength criterion for wellbore stability analysis of Longmaxi shale. 1. Introduction With the impact of the successful development of shale gas in North America, the world is also taking adequate measures to increase the exploration and development of unconventional oil and gas, such as shale oil and gas, tight sand oil and gas, coal-bed methane (Ma et al., 2015; Soder, 2018; Jiang et al., 2020; Wang et al., 2020; Wu et al., 2020; Nie et al., 2021). However, the reservoir rocks of unconventional oil and gas are rich in bedding, fissures, joints, cleavage, and other weak planes, resulting in the strength anisotropy of such rocks. The existence of strength anisotropy has brought significant challenges to oil and gas exploration and development. For example, strength anisotropy makes the borehole more likely to collapse and become unstable (Fjar et al., 2008; Aadnoy and Looyeh, 2019). According to statistics, the cost of dealing with borehole instability accounts for more than 15\% of the entire investment and development (Fjar et al., 2008).

ABSTRACT: There are many factors affecting the productivity of Multi-fractured horizontal wells (MFHWs) in tight reservoirs and the relationship is complex, which makes productivity prediction very difficult. In this paper, firstly, the analytic hierarchy process (AHP) and grey theory were used to quantitatively calculate the weight coefficient of influencing factors, clarify the main controlling factors of productivity. The threshold of reservoir classification was determined by inflection point method. Secondly, the productivity prediction method was established by coupling reserve capacity parameters and completion efficiency parameters, and the fracturing effect and productivity of horizontal wells were predicted by calculating comprehensive evaluation factors. The results shown that the main factors affecting production were as follows: horizontal section sandstone length, formation pressure, stages of fracturing, amount of proppant, permeability, porosity, oil saturation, net pay thickness, and fracturing fluid volume. The reservoir quality in the study area can be divided into three types: type I > II > III, and the classification thresholds are 0.30, 0.35, 0.40 respectively. There is a good correlation between the initial productivity of horizontal wells and comprehensive evaluation factors. This study has important reference significance for the fracturing optimization design of similar tight oil reservoirs. 1. Introduction China is rich in tight oil reservoirs, which are mainly distributed in large basins such as Ordos Basin [1], Junggar Basin [2-3], Songliao Basin [4-5], and Sichuan Basin [6-7]. The multi-stage fracturing technology of horizontal well has realized the commercial development of unconventional resources [8-11]. Due to the unclear understanding of many influencing factors, such as geology and engineering, and the mismatch between horizontal well completion efficiency parameters and reservoir parameters [12-13], there is a great difference in post-fracturing production [14-15]. The prediction and evaluation of well productivity has important significance for the exploration and development of tight oil reservoirs. However, there are many factors affecting productivity, and the relationship of each parameter is complex, which plays a different role in fracturing effect at different levels [16-19]. Therefore, how to comprehensively consider the factors affecting the productivity of horizontal wells, identify the main control factors and predict the productivity after multi-stage fracturing is particularly important for the efficient development of tight oil reservoirs.

ABSTRACT: Understanding the true failure mechanism of rock and rock-like materials has been a significant challenge in rock mechanics particularly in the rocks with high brittleness where the sample fails rapidly under complex mixed mode of shearing and multiple tensile cracking. This study presents the results of an experimental investigation on the failure mechanisms of two different rock types from sedimentary and igneous origins. A set of commonly used brittleness indices (BI) were deployed to measure the rocks' brittleness, then with the aid of high-speed imaging technique, the failure mechanisms of sandstone and granite were compared. The behavior of samples was monitored from the commencement of loading until the complete failure using the Phantom high-speed camera under uniaxial compression. The various stages of cracking process were captured with high resolution including crack initiation, coalescence and failure. Finally, it was found that the granite samples have the most violent failure mechanism under both uniaxial compressive and indirect tensile loadings being 17 times faster failure rate than the sandstone samples under uniaxial compression. Majority of the selected brittleness indices recognized granite as the most brittle rock which was in a good agreement with the data obtained from the high-speed imaging. 1. Introduction The brittleness is one of the most important mechanical properties of materials and was firstly defined as the lack of ductility or the lack of ability to endure a large plastic deformation without fracture (Hetenyi 1950). Brittleness has an important application in rock bursting identification (Hucka and Das 1974; Zhao et al. 2014). The brittleness or its index has been used in different rock engineering projects including hydraulic fracturing operation for simulating the oil and gas reservoirs (Feng et al. 2020; Zhang et al. 2016), predicting hard rocks drill-ability and cutting efficiency to determine the progress of excavation in civil and mining structures (Altindag 2002; Altindag 2003) and estimating the tunnel boring machine (TBM) performance. Although the brittleness is a tangible concept, its quantification has long been ambiguous as it depends on a number of intrinsic and mechanical characteristics. Multiple factors need to be considered to conceive the brittleness of rocks including mineral composition (Jarvie et al. 2007; Wang and Gale 2009), mechanical and strength properties (Bishop 1967; Sun et al. 2013), size and time (Hajiabdolmajid and Kaiser 2003), and fracture energy (Tarasov and Potvin 2013). Providing a method to measure the brittleness which covers all the above-mentioned factors is not applicable. Thus, it has been attempted to consider only the most influential factors in the rock brittleness approaches. Significant attempts have been undertaken to quantify the brittleness by scholars since 1967 leading to establishment of over 80 different formulas in which each has its own limitations based on the selected influential factors. It is evident that one model alone cannot include all the affecting factors.

ABSTRACT: The Panna Formation is the oldest hydrocarbon-bearing tertiary sedimentary unit in the Western Offshore Basin (WOB). Drilling in Panna is plagued by sudden pore pressure ramp resulting in the mud gain and mud-loss situation. A comprehensive study is carried out across 5 blocks of WOB to establish the root cause of pressure ramp and implement preventive measures. It includes characterization of overpressure mechanism and steps for predictive modelling for planned locations. The first step involves the collection of information related to drilling complications, drilling parameters, and geophysical logs in Panna Formation. In the second step, geomechanical models are constructed giving an understanding of the profile of pore pressure gradient (PPG), vertical and horizontal stresses, and elastic and strength properties. Crossplots between velocity-density, velocity-effective stress, effective stress-density, and pore pressure-neutron porosity have been used to establish the overpressure mechanism. Wells are correlated on a regional scale to ascertain the variation of lithofacies corresponding to the onset of overpressure. Variation of geothermal gradients is also studied for Panna and associated formations above. Panna Formation exhibits variable PPG and ranges from hydrostatic to approximately 16.0 lbm/galUS. It is found that areas with thicker Panna Formation and a higher percentage of coal lithofacies show overpressure compared with other areas. The initiation of PPG ramp is sharp with variable with depth. PPG increases by 5 to 6 lbm/galUS within 100–200 m interval, separated by a pressure seal with a sealing capacity of 3,000–4,000psi. In certain areas, ramp starts from the lower Bassein Formation, while in others it starts near the mid of Panna. Isolating high-pressure interval from near-hydrostatic interval requires accurate predictive modelling and inability to construct such predictive models results in well flow and mud loss situations. The coal lithofacies are likely to be the zone having losses due to their inherent lower fracture gradient. Standard crossplots in multiple wells indicate that the overpressure mechanism is of hybrid nature, classified as a Type-II mechanism. Under this mechanism, PPG is identified to be independent of porosity as the interval is repressurized. One possible phenomenon occurring inside the Panna formation is the thermal cracking of hydrocarbons. Coals, as a source of hydrocarbon, have been established in many basins across the world. Hydrocarbon maturation in a "closed" environment could lead to such overpressure. Presence of montmorillonite and illite clays indicate probable smectite to illite transformation, releasing water and pressurizing in the existing pore space and building up pressure in the existing pore space. Spectroscopy measurements also suggest the presence of high organic matter in some of the shales of Panna Formation.

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: Rocks have a wide range of densities because of mineralogy and porosity variations. This bulk density is a key property and playing an essential role in geologic structure interpretation and reservoir characterization, which help in well planning, drilling optimization, and completion and production strategies development. The practical measurements of rock density in the field are either through logging while drilling tools or wireline logging techniques, but with discontinuity and tools limitations. This work aims to develop a model for predicting real-time bulk density of complex lithology during drilling by utilizing the functional networks (FN) technique and using the drilling mechanical parameters as inputs. A vertical well containing sand, shale, and carbonate with 2912 data points was used to build the model. Several methods and types in FN algorithm were tested to obtain the best model. The obtained results showed that the developed model has high accuracy in both training and testing processes with correlation coefficient (R) and average absolute percentage error (AAPE) values of 0.98 and 1.1%, respectively. The model was validated with another well form the same field showing R and AAPE values of 0.98 and 1.2%, respectively. The developed reliable and robust model in this study can predict the real-time bulk density with high accuracy, which assists in formation characterization in a convenient method within the least time, effort, cost, and errors. 1. Introduction Because of mineralogy and porosity variations, rocks have a wide range of bulk density ( ρ b ), which is a key property that has an essential role in many interpretations (Reichel et al., 2013). It is required for identification of porosity (Spross et al., 1993; Ellis, 2003), lithology and fluid content (Alger and Raymer, 1963), overburden and pore pressure (Burrus, 1998; Swarbrick, 2001; Zhang, 2011; Satti et al., 2015; Oloruntobi et al., 2018; Oloruntobi and Butt, 2019a), and geomechanical features such as shear modulus, bulk modulus, Young's modulus and rock matrix compressibility (Coates and Denoo, 1981; Chang et al., 2006; Ameen et al., 2009; Najibi et al., 2015; Adewole et al., 2016; Feng et al., 2019). Hence, prediction of rock density is highly important for interpreting subsurface geologic structure and reservoir characterization to develop well planning, drilling optimization, and completion and production strategies development (Onalo et al., 2018; Oloruntobi and Butt, 2018; Yusuf et al., 2019).

ABSTRACT: Continental shale gas is a new field of unconventional oil and gas resources. Systematic research on the rock mechanical properties of continental shale after being soaked with fracturing fluid is extremely scarce. For the first time, 7 types of continental shale cores of different strata with 30 m depth variations in the Sichuan Basin were obtained. Two sets of tri-axial compression experiments before and after soaked were compared. Three quantitative indicators were used to evaluate the macroscopic fracture characteristics of samples: the 3D scanner was used to scan the main failure surface, and the root mean square was used to calculate scanned point cloud data; a simpler index for calculating roughness based on area variation was established; the surface crack morphology of the sample was drawn by high-resolution photos, and the crack complexity was quantitatively described based on box-counting method in fractal dimension. The results show that the impact mechanism of fracturing fluid immersion on the shale at different sampling locations is different, which can be summarized as two types: lubrication dominated and softening dominated. It provides certain guiding significance for the variation of mechanical properties and brittleness assessment of continental shale under the influence of fracturing fluid immersion. 1. Introduction In recent years, typical shale gas resources has developed rapidly, the oil and gas theory and fracturing technology have been upgraded, and the field of exploration and development is constantly innovating and making breakthroughs. With the increase in demand for energy and unconventional resource exploration (Jiang et al., 2017), it is very urgent and important to drive the technological development of various unconventional oil and gas resources including different types of shale gas to improve the energy structure and resource shortage. Continental shale gas resources, as a brand-new field of unconventional energy strategy, are still in the stage of geological evaluation and industrialized mining experiment exploration (Dong et al., 2016)(Zhai et al., 2018).

ABSTRACT: The volume fracturing has become an effective technology for the development of shale oil reservoir in Shengli Oilfield. For multi-layer tight sandstone reservoir with thin mudstone, effective control of fracture height and use of stress interference are the keys to form complex fracture network. In this paper, a two-dimensional fracture propagation model is developed. The finite-discrete element method is used to describe the propagation of the fractures. In this model, the rock matrix units are discretized to obtain a discrete fracture network (DFN). The natural fractures are considered by the DFN model. And then, zero-thickness cohesive elements are embedded to characterize natural fractures and hydraulic fractures. A new traction-separation law is used to describe the damage process of hydraulic fractures. The Mohr-Columb failure criterion is applied to natural fractures. The fluid flow in the fractures is modeled by the lubrication equation. Finally, the flow-stress-damage coupling finite element equation is solved by explicit integration algorithm. A case of the shale oil reservoir in Shengli Oilfield is proposed to study the fracture propagation behavior. 1. Introduction Shale oil have huge development potential and have become a hot spot for unconventional oil and gas exploration and development in China. Many shale oil reservoirs occur in formations with laminated rock and obvious bedding planes (BPs). In addition, the stress, rock properties and interface strength of each layer are different. Due to the reservoir geomechanical characteristics, the propagation mechanism of hydraulic fractures (HFs) is complicated. Field fracturing treatment showed that the fracture height is difficult to reach the predicted value even with a high injection rate. And microseismic monitoring during hydraulic fracturing also demonstrated that the propagation of the HFs in the height direction is not ideal (Kahn et al., 2017; Zhang et al., 2017). Numerous fracturing treatment cases have showed that the penetration ability of the HFs is limited in the formations with rich BPs, which restricts the effect of shale oil development.

ABSTRACT: This paper presents a time-lapse three-dimensional (4D) geomechanics evolution model based on long-term drainage of coalbed methane (CBM) reservoir, which can couple the finite difference reservoir simulator with the finite element geomechanical simulator. In the model, the heterogeneity of geological structure and geomechanical properties were involved. A numerical model of Block A in Qinshui Basin CBM reservoir (China) was built based on this modelling method. To improve the methane production rate of the Block A in Qinshui Basin CBM reservoir (China), refracturing has been taken into consideration. However, the stresses are changing during the CBM production, which will change the hydraulic fracture geometry of the refracturing well. To accurately predict the stress evolution, the proposed 4D geomechanics model is a good solution, and it also can be applied for CBM production system optimization, wellbore stability analysis in infill wells and refracturing optimization design. According to the well selection criteria based on the stress changes, six candidate wells for refracturing in Block A of Qinshui Basin were finally selected. The refracturing well selection scheme was applied to the field, and it shows that the actual gas production of the selected refracturing wells after refracturing is more obvious than that of the un-optimized refracturing wells. 1. Introduction China is a country with abundant coalbed methane (CBM) resources (Zou et al, 2014; Zhao et al, 2016; Qin et al, 2018). And CBM has carried out large-scale commercial exploitation (Yang and Zou, 2019; Yang et al, 2019; Song et al, 2012). The Qinshui Basin is the main block of Chinese CBM development (Fan et al, 2019; Qiao et al, 2008). The Block Ais located in the southeast of the Qinshui Basin, where coal seams are generally thick. And the developed coal seams are the Shanxi Formation 3# and Taiyuan Formation 15# in this block. The exploitation of the 15# coal seam is restricted by mineral filling, low permeability and poor pore structure. Because the Shanxi Formation 3# depth is shallower with stable formation pressure, it is the main development coal seam in the early stage development of the block. And it has been in production for more than 10 years, with a cumulative gas production of 17.8×10 8 m 3 .