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Abstract The bi-axial stress test is a two-dimensional (2-D) field test in which horizontal and vertical stresses are applied to a circular “hole in the plate” problem. The diametric closures are measured at three uniformly spaced locations. Using the Kirsch solution, and assuming an isotropic elastic medium, the magnitude of the in-plane far-field principal stresses (𝜎1, 𝜎2) and their orientation (𝛼) can be uniquely determined. However, the Kirsch Solution has limitations, since the two-dimensionality is applicable only for conditions of plane strain or plane stress; and in reality, the out-of-plane stress condition is somewhat in between. The major outcome of this paper is the development of a methodology to determine the three-dimensional principal stresses (𝜎1, 𝜎2,𝜎3) and their orientations (𝛼,𝛽,𝛾) using the two-dimensional Kirsch Solution in three mutually perpendicular planes. Introduction The Sanford Underground Research Facility (SURF, formerly known as DUSEL) is a dedicated underground scientific research facility located in Lead, South Dakota, at the former site of the Homestake gold mine. The SURF mission includes the construction of large underground cavern openings at depths of about 1500 meters to house large-scale physics experiments. A primary rock mechanics concern is the stability of these proposed large-diameter caverns (up to 165 meters) in a host rock which has been characterized to be orthotropic in the following conditions: (1) geometry, (2) in situ stress, (3) elasticity, and (4) strength. Of these four conditions of orthotropy, the second dimension (in situ stress) will be examined in this paper. The objective of this research is to present the theoretical development and implementation of the equations that define two- and three-dimensional orthotropic in situ stress. The equations are developed based on an interpretation of the biaxial stress test in two dimensions and extrapolation of multiple orthotropic field test results in three dimensions. The two-dimensional results are presented in the next section. These two-dimensional equations are used in the development of the three-dimensional equations for determination of the principal stress magnitudes and orientation, which are given in the subsequent section. The method is validated with a numerical example and will be applied to a data set of test results performed in situ to determine the orthotropic stress state (both magnitudes and orientations) in an underground mining location. The results of this mathematical development are applied to an orthotropic biaxial stress field test in Section 4, followed by a number of important conclusions in Section 5. The paper is concluded with a list of applicable references and several supporting figures and tables of results.

Abstract Low-porosity, extra-low-permeability tight sandstone oil and gas reservoirs have become an important research area for hydraulic fracturing. Sand-mud interlayer is often developed in this type of reservoir in the longitudinal direction. The heterogeneous distribution of oil layers and mud shale barrier layers in the longitudinal direction will lead to restrict propagation of hydraulic fractures in the fracture height direction, which affects the effective stimulated reservoir volume significantly. In this paper, a finite element model of hydraulic fracture propagation in sand-mud interlayer was established based on the real characteristics of the target block formation to study the hydraulic fracture penetrating propagation feasibility under different combinations of fracturing parameters in the tight sandstone reservoir in the target block, and the model verification was completed with the field data. A total of three types of variable orthogonal combinations of 7 kinds of viscosities of fracturing fluid, 5 kinds of injection rate and 8 kinds of thicknesses of barrier layer were carried out to explore the penetration feasibility of hydraulic fracture under the commonly used combination of low injection flow rate and high viscosity in offshore and high injection flow rate and low viscosity in onshore shale gas reservoirs. And the feasibility evaluation plate of the hydraulic fracture penetration propagation in sand-mud interlayer is established. The method for evaluating the feasibility of hydraulic fracture penetrating propagation in sand-mud Interlayer under different combinations of fracturing parameters can be well applied to the tight sandstone reservoir in this paper. And it will provide theoretical guidance for hydraulic fracture design and fracturing parameter optimization. In addition, the method can also be applied to the fracturing development of shale reservoirs with sand-mud interlayers.

Abstract Fracture-cavity carbonate reservoirs have abundant reserves of crude oil in place, but they are composed of matrix, fractures and cavities of various sizes, and characterized by strong heterogeneity. Fracture-cavity carbonate reservoirs in China are typically discovered with depth higher than 5000 m at high temperature, high pressure and strong stress. The deformation of fracture and cavity exerts a great impact on fluid flow, while the traditional continuum mechanic theory is inefficient to cope with the strong fluid-solid coupling effect occurred in this type of reservoir. This paper proposes an embedded discrete fracture-cavity model considering fluid flow and solid deformation in order to perform transient production analysis during depletion-drive stage of fracture-cavity carbonate reservoirs. Based on the double logarithmic characteristics of typical production history curve, oil production of fracture-cavity carbonate reservoirs can be divided into four stages: fluid flow in fracture, transition from fracture to cavity, response to cavity and boundary control. Bottom water only affects the fluid flow when entering the boundary-control stage, which can greatly inhibit the sharp decline of oil production history. By accurately conducting transient production analysis, true reservoir properties in actual fracture-cavity unit can be obtained by numerical inversion of production history. The proposed methodology provides a theoretical support for understanding reservoir fluid flow in fracture-cavity carbonate reservoirs. Introduction Fracture-cavity carbonate reservoirs are widely distributed in the Tarim basin, China, generally with depth higher than 6000m[1]. Various reservoir spaces exist simultaneously including matrix, fracture and cavities of different sizes in this type of reservoir. Strongly affected the high in-situ stress, severe heterogeneity, various reservoir spaces and complicated oil-water relationships, depletion-drive development is mainly enforced. The natural decline of oil production is larger than 25%, and there exists a great difficulty to further improve production performance[2-5]. The traditional continuous theory is no longer suitable, and great efforts have been made to clarify to underlying mechanism of fluid exchange and its effect on actual oil production[6,7]. To resolve these issues, an embedded discrete fracture-cavity model considering the fluid flow and solid deformation is proposed in this paper, and used to carry out transient production analysis to investigate the underlying fluid flow during depletion-drive development. Using the proposed methodology, the reservoir properties of actual fracture-cavity carbonate reservoir are further estimated.

Abstract The city of Sydney (Australia) is currently undergoing a major infrastructure construction boom, with numerous rail and road tunnels currently under construction. This paper presents DFN modelling undertaken as part of the tunnel design process for a major road tunnel system in western Sydney. The primary discontinuities controlling block formation are expected to be joints, bedding planes and seams / bedding plane shears, which were included in the DFN model. This paper presents the necessary input parameters for the modelling and derivation of these parameters, along with the model generation process. Multiple realizations of the model were generated, with a stability analysis carried out on each. Given the complicated geometry of the tunnels in the project two representative 100 m lengths of tunnel geometries were analyzed; a wide span cavern (striking 020°) and a mined tunnel (striking 125°). The stability analyses were used to develop the unstable block volume distribution and identify the maximum likely block volume for the crown and sidewalls of the cavern. In addition, the block results were filtered relative to the proposed pattern rock bolting to assist designers with considering shotcrete loads.

Abstract This paper presents the development of a three-dimensional (3D) geotechnical model for an existing water dam in Queensland, Australia. The model incorporated data from historic construction records, recent investigation data as well as previously developed two-dimensional cross section interpretations and geological mapping records. The 3D model provided the project team and other stakeholders the ability to interrogate the ground model to an unprecedented level of detail. The geotechnical model development was complimented by an in-depth rock mechanics assessment to investigate kinematically feasible sliding mechanisms beneath the dam spillway and abutments. This package of work included creation of a discrete fracture network model. The DFN modelling in this study was undertaken in two stages, with an initial model built to be representative of sub-horizontal fractures (with a dip of The paper presents the input parameters, derivation of these parameters along with the model generation process are presented for both stages. The modelling was undertaken for both rock mass visualization and sliced on two cross-sections for input into 2D Finite Element analyses. This was particularly targeted at understanding intact rock forming bridges between laterally persistent defects within the volcanic host rock that were previously identified as a key risk to dam stability in the event of an overtopping event.

ABSTRACT: This paper presents an assessment of well drilling strategy and the associated hydraulic fracture stimulation for a field in the Northern DJ Basin, Colorado. The paper is rich in data related to well orientation, completion, and production over a ten-year period from an unconventional field. Shale formations have very low permeabilities; however, multistage hydraulic fracturing stimulates the rock matrix by inducing micro- and macro-cracks; thus, improving formation drainage. Subsequently, rate transient analysis (RTA) of production data determines the quality of well stimulation. RTA emanates from single-phase linear-flow theory using rate-normalized-pressure versus (Equation) of the production data; however, RTA also extends to multiphase flow. RTA yields the effective formation permeability (EFP) and, occasionally, hydraulic fracture conductivity (HFC). Additionally, we used an iterative Perkins-Kern-Nordgren (PKN) model to interpret diagnostic fracture injection tests (DFIT) for the unstimulated formation permeability. Finally, we used 21 variables to generate a ‘correlation map’ of various reservoir performance measures: well s pacing, lateral length, number of perforations, total stimulation fluid injected, amount of sand placed, sand mesh size, quantity of p roduced oil, gas, and water. The variables that yielded the strongest positive correlation coefficients were well spacing, produced oil and gas volumes, 20/40 sand, acid additives, EFP, and HFC. 1. INTRODUCTION The Shale formations are denoted as ‘tight’ reservoir plays with low, nano-Darcy, matrix permeabilities where pore-size distribution is in the nanometer higher frequencies (Luo, 2018). Because of low matrix permeability, the maturation of the organic matter takes place in the source rock and the resultant distribution of hydrocarbon components also remains within the source rock with little outward migration. Formations with such characteristics are designated ‘unconventional reservoir’. There is a continued demand for hydrocarbon production due to the global energy demand and population growth. Fortunately, innovations in the technological sector of the oil and gas industry has provided effective means of oil and gas recovery from such tight formations (Kazemi et al., 2015). Contribution of unconventional reservoirs is significant in maintaining the balance in the energy market (Cui, 2015).

ABSTRACT: Analysis of the stress field around the wellbore is a prerequisite for predicting the formation breakdown pressure. With the development of hot dry rock and deep oil and gas reservoirs, thermoelastic stress has become one of the significant factors in the analysis of the stress field around the wellbore. Based on linear elastic theory and heat transfer theory, this paper analyzed the effect mechanism of thermoelastic stress around the wellbore by establishing a two-dimensional wellbore physical model. Through the finite difference method, this paper simulated the thermoelastic stress field around the wellbore under quasi-static and transient conditions. Numerical simulation results show that the calculation results of the finite difference scheme established in this paper are consistent with the analytical solutions under quasi-static conditions. The finite difference scheme established in this paper can accurately calculate the thermoelastic stress field around the wellbore. When the cold liquid injected from the wellbore acts on the hot rock, the circumferential tensile stress is generated around the wellbore. With the increase of Young’s modulus, Poisson’s ratio, and the linear expansion coefficient of the rock, the thermoelastic circumferential stress value around the wellbore increases significantly. The faster the cooling rate of the wellbore, the greater the thermoelastic circumferential stress generated around the wellbore. The finite difference solution of the thermoelastic stress field established in this paper can provide theoretical guidance for the design of hot dry rock hydraulic fracturing and drilling fluids. INTRODUCTION Hydraulic fracturing is a significant development technology for unconventional reservoir exploitation (Wang et al., 2021). With the increase of reservoir mining depth and the development of hot dry rock, the influence of thermal stress during hydraulic fracturing becomes more and more important (Zhou et al., 2020). The heat exchange between the fracturing fluid and the reservoir causes the rock temperature to change, which in turn generates thermal stress. Thermal stress will directly change the effective stress field of the reservoir and affect the failure of the wellbore and the propagation of fractures (Wang and Papamichos, 1994). Chen and Ewy (2005) found that heating the wellbore increases collapse and fracturing mud weight, destabilizing the near-wellbore area. Ghassemi et al. (2009) established a coupled thermoelastic model of a chemically-active rock, which showed that cooling high-salinity mud would increase the possibility of tensile failure. Zhou et al. studied the stress field formed by the seepage force around the wellbore and analyzed the effect of poroelastic stress on the initiation of fractures (Zhou et al., 2021; Wang et al., 2021). Zhou and Ghassemi (2009) developed a finite element model that couples linear and nonlinear chemistry-pore-thermoelasticity, which can be used to analyze the wellbore stability of shale reservoirs. Roy et al. (2018) studied the effect of thermal stress on the integrity of the wellbore during the CO2 injection process, and the results show that the existence of effective in-situ horizontal stress reduces the negative impact of the thermal stress around the wellbore. Wang et al. (2019) developed a new non-isothermal wellbore strengthening model, which showed that mud loss aggravated the redistribution of thermal stress near the wellbore. The above studies have shown that during fluid injection, thermal stress has a significant impact on wellbore stability. It is necessary to study the thermoelastic stress generated by the cooling effect of the fracturing fluid during the hydraulic fracturing process to analyze the initiation of the hydraulic fracturing fracture.

ABSTRACT: The pressure-bearing capacity of the micro-fractured formation is low, and the leakage phenomenon is serious under the action of high-density drilling fluid. The pressure-bearing plugging can improve the pressure-bearing capacity of the formation that is vulnerable to leakage. In this paper, the sandstone outcropping was made into 295mm×297mm×300mm samples to conduct true triaxial pressure-bearing plugging physical experiments. The result shows:(1) Large granular lost circulation materials were accessible to accumulate around the open hole to form a dense mud cake, which greatly improved the pressure-bearing capacity of the formation. (2) Under the action of high pressure, the small granular lost circulation materials were rapidly pumped into the micro-fractured formation, forming a plugging layer in the fracture. (3) It was found that when increasing the plugging slurry injection rate, the plugging zone was more prone to instability, and the final pressure-bearing value of the formation was reduced. This study explored the plugging effect of lost circulation materials with different particle sizes and ratios on the fractures and optimized the corresponding construction parameters by carrying out true triaxial pressure-bearing plugging experiments in micro-fractured sandstone formations under different working conditions, in order to provide guidance for pressure-bearing plugging site construction of micro-fractured sandstone formations. 1. INTRODUCTION Loss circulation refers to a phenomenon in which the drilling fluid in the wellbore is lost to the formation under the action of the pressure difference during the drilling operation[1]. Economic losses to the global oil industry due to lost circulation run into millions of dollars each year. Pressure-bearing plugging technology[2,3,4] is a method for plugging lost formations and fractures when lost circulation occurs during the drilling process, which is significant to drilling engineering. The pressure-bearing plugging technology is to use different shapes and sizes of lost circulation materials to mix with drilling fluids in different concentrations by bridging, stacking and filling to form a plugged zone. The plugged zone can block fluid pressure transmission and fluid medium passing through. It reduce leakage, meet the needs of control and cementing by improving the pressure bearing capacity and bottom-hole pressure of low-pressure and weak formations[5,6]. Because of the low pressure-bearing ability of the micro-fracture formation and the serious leakage phenomenon under the action of high-density drilling fluid[7]. This paper carried out pressure-bearing plugging experiments based on the actual micro-fracture formation stress field, researched the effect of plugging slurry injection speed on the pressure-bearing capacity of the sandstone formation and different particle size ratio on the plugging effect of induced cracks by analyzing the pumping pressure curve.

ABSTRACT: The matrix is dense for deep cavernous carbonate reservoirs in Tarim Basin, and oil and gas are mainly enriched in caves. We hope that hydraulic fractures can communicate with more caves. However, the existence of caves will disturb the stress field and influence hydraulic fracture propagation. Thus, the interaction between hydraulic fractures and caves and whether they can penetrate caves has a significant impact on the fracturing efficiency of cavernous formation, which is worth studying. This paper studied the interaction rule between hydraulic fracture and a 3D single cave by discontinuous discrete fracture model (DDFM). In this model, the cave was set as a three-dimensional sphere with fluid in it, which is located in the maximum horizontal stress direction along one side of the vertical well. The initial hydraulic fracture is perpendicular to the direction of minimum horizontal stress. The fluid-solid couple action, fluid flow, and mass transfer during fracturing were considered. By means of the control variable method, we analyzed the intersection characteristic between hydraulic fracture and a cave and whether it could be penetrated. The results show that when hydraulic fracture approached close to a cave, it expanded to the side of the cave preferentially due to an attraction action. After they intersected, hydraulic fracture turned to expand along height direction at the intersection to break the cave wall because of stress concentration. However, they encountered resistance when hydraulic fracture opened most of the cave wall and tried to penetrate. Under limited injection volume conditions, whether hydraulic fracture can penetrate and continue to expand was related to cave diameter, in-situ stress, the distance between the cave and well, filtration coefficient, and injection rate. This paper revealed the propagation characteristics and morphology of hydraulic fracture interacting with a 3D cave, which could help understand the interaction between hydraulic fracture and a 3D cave and provided a reference for optimizing the fracturing parameters of cavernous carbonate reservoirs.

ABSTRACT: Understanding how the fireball from a nuclear detonation interacts with its environment is essential to predicting the post-detonation environment, including fallout composition and form. Realistic scenarios for nuclear events inevitably involve complex environments, such as urban settings, however the majority of data informing fallout processes come from environments devoid of relevant buildings or other structures. This paper summarizes recent developments in simulations of above-ground nuclear explosions as part of a broader effort to better characterize conditions within a fireball that may influence the chemical evolution of bomb materials and other materials entrained from the local explosion environment. We discuss our recent improvements in modeling of the coupling of radiation transport and mechanical deformation, as well as the transition from intact materials (e.g., rock, concrete, etc.) into airborne particulates. The entrainment process is particularly important to our investigations because entrained materials are a predominant influence on the chemistry and form of resultant fallout. 1. INTRODUCTION This paper discusses recent efforts as part of an internal research project at Lawrence Livermore National Laboratory to improve our understanding of the post nuclear detonation environment, including the chemical evolution of species within the fireball, addressing both bomb debris and entrained material. The motivation is to be able to provide actionable information for both forensic (e.g., establishing responsibility for an event) and consequence management (e.g., predicting the activity of respirable particles). Our goal is to be able to simulate complex scenarios that involve conditions outside of historical testing experience, including, for example, an event at street level in an urban environment. Modeling of such scenarios involves capturing a number of physical and chemical processes that span a range of spatial and temporal scales. Fig. 1 shows the approximate sequence of events and associated processes. At early time, the outgoing shockwave and radiation cause damage and vaporization of immediate geologic materials and structure prior to entrainment into the evolving fireball. It is critically important to capture the geomechanical processes at this stage of fireball evolution. The vaporization, pulverization, and comminution of the geologic materials will determine how much mass introduced into the fireball at early time. This entrained material plays at least two critical roles. First, the entrained mass will cool the fireball, leading to more rapid condensation of materials from the plasma state. Second, the entrained material introduces additional chemical species that contribute to subsequent fallout formation. As the fireball expands and radiates, the initial plasma state cools and individual atoms and molecules can develop. During this phase, it is important to be able to predict what specific molecules develop, because some molecules are more refractory than others. For example, depending upon how much oxygen is available, different oxidation states will be achieved with different melting points. Consequently, modeling the mixing of the fireball with both entrained materials and with the atmosphere is key to predicting the initial formation of fallout relevant radionuclide species. With further cooling, nucleation and condensation of particles occurs, and they are subsequently transported to the surrounding environment.

ABSTRACT: X Oilfield is located in the southern Bohai Sea. The formation fractures of the Neogene Minghuazhen Formation are developed. During drilling, wellbore collapse and block falling are prone to occur, and even cause stuck and stuck drilling. This paper presents a comprehensive geomechanical method which combines theoretical analysis with numerical simulation. By collecting a large number of geological, seismic, drilling and logging data, this method selects the appropriate theoretical model to predict and calculate the ground stress, pore pressure, fracture pressure, collapse pressure and rock mechanical parameters of well A, and draws the formation four pressure profile, and then obtains the safe drilling fluid density window of the well. In this paper, based on the elastic-plastic mechanics theory, the stress state of the wall rock is analyzed, and the numerical simulation of wellbore stability is carried out by using ABAQUS software. The influence of pore pressure, formation strength and drilling fluid density on wellbore stability is analyzed, which provides a powerful tool for understanding the wellbore instability mechanism of the target block of X oilfield, and effectively controls the wellbore instability phenomenon of Well A. 1. INTRODUCTION Since the 21st century, China has gradually focused on offshore oil and gas development in the context of the gradual depletion of conventional oil resources on land. Overall, there are relatively abundant oil and gas deposits in Chinese offshore areas. China’s offshore oil and gas resources are abundant in general. In recent years, Bohai Basin has made significant oil and gas discoveries and has a good development prospect. It is the main offshore oil and gas production area in China . The target well in this paper is well A, which is located in the south of Bohai Sea. The core technology of offshore drilling and completion and the stability of borehole wall are the key issues for the smooth development of offshore oil and gas resources. The theory and research results involved in this paper can not only provide scientific guidance for well A, but also provide theoretical support for the well area of the oilfield and even for the drilling of Bohai Bay in China, which has very important engineering guiding significance.

ABSTRACT: Previous studies have found that the horizontal extension capacity of extended reach wells is affected by drilling fluid density and displacement, and a single parameter is optimized by taking the extension limit as the objective function. In this paper, the maximum open hole extension capacity is taken as the objective function, and the drilling fluid density and displacement are taken as the constraint conditions, the nonlinear programming equations are established, and dual parameters (drilling fluid density and displacement) are optimized. The density window was determined on the premise of wellbore stability, and the displacement range was determined on the basis of hydraulic conditions. Due to density will affect the selection of optimal displacement, a set of cyclic algorithm is designed to modify density and displacement. According to the analysis and calculation of an extended reach horizontal well, when the density is 1.02 kg/cm3 and the displacement is 20 L/s, the maximum open-hole extension capacity is 7028 m. 1. INTRODUCTION In order to reduce drilling costs and increase drainage area, extended reach horizontal wells have been widely used in offshore oil and gas exploitation and shale gas exploitation in remote mountainous areas. When the reservoir is long and rich in oil and gas resources and the cluster wells are producing distant oil and gas reservoirs, it is necessary to maximize the lateral extension capacity to reduce costs and achieve greater oil and gas revenue. Gao systematically proposed the concept of extension limit for the first time, taking into account wellbore stability, hydraulic factors, drilling equipment and other influences, dividing the extension limit into open hole extension limit, hydraulic extension limit and mechanical extension limit (Gao et al., 2009; Gao et al., 2018). Wang et al. established a hydraulic extension limit model, taking into account the limitations of hydraulic equipment on the extension limit (Wang et al., 2008). Subsequently, Chen and Li et al. improved the theoretical model of open hole extension limit (Chen et al., 2018; Chen et al., 2018; Li et al., 2018). In the extension limit theory, drilling fluid density and displacement are closely related to the extension limit and directly affect the extension limit of horizontal section of extended reach wells, so it is of great significance to the optimization of drilling fluid density and displacement. A large number of scholars have determined the application range of drilling fluid density and displacement respectively (Tan et al.,2012). Li et al firstly optimized drilling fluid displacement based on elongation limit (Li et al.,2017). This paper focuses on the maximum open hole elongation, that is, the maximum elongation of horizontal wells with extended reach under the condition of stable borehole wall. Drilling fluid density and displacement will affect borehole stability, thus affecting the open hole elongation capacity. However, the density and displacement are artificially controllable. Therefore, reasonable drilling fluid density and displacement can be selected to maximize the open hole elongation capacity.

ABSTRACT: Different scholars had carried out much research on rock damage during perforation by numerical simulation or experiment, but they had not considered the influence of metal jet morphological feature on rock damage during perforation. In this paper, a numerical calculation model of perforation is established. The paper reveals the change characteristics of metal jet shape during perforation and carries out the influence law of metal jet shape on the rock near pore damage. The results show that: In the process of perforation, the shape of the metal jet changes dynamically with time, and the penetration process of the metal jet is divided into three stages. It is clear that the near channel damage of rock mainly occurs in the third stage of shape change. The paper also clarifies that the rock failure form in the perforation process is compression shear failure and reveals the influence law of confining pressure on the rock damaged area in the perforation process. The paper defines the influence law of metal jet shape and confining pressure on rock damage during perforation, which is of great guiding significance for perforation operation design. 1. INTRODUCTION Unconventional oil and gas resources such as shale gas and shale oil often exist in low porosity and low permeability rocks. Due to the limitation of the storage environment, oil and gas exploitation is difficult (Wu et al.,2016; Lian et al.,2020; Gao et al.,2019). Aiming at the problems in the exploration and development of such oil and gas resources, the combination of perforation completion and reservoir stimulation is used to improve the oil and gas seepage conditions (Zhang et al.,2021; Albert et al.,2018; Wang et al.,2019; Behrmann et al.,1991;). However, while the perforation forms a channel for oil and gas migration, the rocks around the perforation channel will also be damaged to varying degrees. The transient nature of perforation and the complex and diverse rock damage around the perforation channel have severely restricted the stable and efficient development of unconventional and complex oil and gas reservoirs.

ABSTRACT: Weakly consolidated sandstone reservoirs generally feature poor cementation, low strength, relatively high porosity and high permeability. Due to the significant effect of poroelasticity, stress redistribution resulting from the pore pressure perturbation around the injection well should be accounted for when determining the fracture pressure. During the long-term water injection, a flow barrier may form due to large particles plugging on the wellbore wall, likewise, the formation permeability around the well may suffer damage due to fine particles plugging the pore channels. Additionally, tensile failure and shear failure may occur in the weakly consolidated sandstone reservoirs since the pore pressure increases around the injection well. In this paper, we provide an analytical method for fracture pressure calculation of directional injection wells in weakly consolidated sandstone incorporating the effects of wellbore plugging and near-wellbore damage. Wellbore plugging and near-wellbore damage are exacerbated as the water injection, which leads to an increase in the fracture pressure. This paper provides a theoretical reference for the prediction of injection pressure in weakly consolidated sandstone. 1. INTRODUCTION The calculation of the water injection pressure in the oilfield should consider the tubing friction resistance, the pressure loss of the water distribution nozzle, the liquid column pressure and the fracture pressure (Li, 2005). The pressure loss along the wellbore and the bore-hole hydrostatic pressure are available when the amount of water injection is determined. Consequently, calculating the reservoir fracture pressure is the premise for ascertaining the water injection pressure. For the fracture pressure, the actual measured value obtained by the mini-fracturing test or drilling pressure test is preferred, and the empirical formula is used to calculate the fracture pressure when the measured value cannot be obtained (Yang et al., 2021). However, weakly consolidated sandstone reservoirs generally feature poor cementation, low strength, relatively high porosity and high permeability. During the long-term water injection, a flow barrier may form due to large particles plugging on the wellbore wall, likewise, the formation permeability around the well may suffer damage due to fine particles plugging the pore channels, which can easily cause wellbore plugging and near-wellbore damage, resulting in a change in the near-wellbore formation pressure (Zhang et al., 2019). Meanwhile, most of the injection wells in offshore oilfields are mainly directional wells. Existing models for fracture pressure prediction have not covered the above-mentioned factors for directional injection wells in weakly consolidated sandstone.

ABSTRACT: This paper focuses on the validation of the Moving Reference Point (MRP) technique using an independently pressure-matched planar commercially available 3D hydraulic fracturing simulation model with real field cases like multiple perforations and laminated reservoirs. The paper provides a methodology for concluding the lessons learned from hydraulic fracture treatments and taking the right preventative action in the hydraulic fracture treatments. The fracture propagation events like normal fracture propagation, height propagation, or propagation in the excessive leak-off zone were simulated on the pressure calibrated planer 3D model matched the event detected using the moving reference point based on the recorded bottom hole pressure. The integration of simulation and analysis presented in this paper assesses the use of the MRP technique to detect fracture propagation events during the fracture treatments in wells where accurate simulation data is not available. Unlike the previous applications of MRP, this application has complete well-completion data and petro-physical information. INTRODUCTION Detection of fracture events during fracture execution has a crucial role in the optimization of hydraulic fracture treatment it is a one-time operation. Once the optimum design is not achieved during execution, it couldn’t be achieved again. Consequently, taking the right action during fracture treatment is crucial in the success of hydraulic fracture and achieving the optimum post-fracture production. The pumping rate or fluid viscosity can be modified or call for an early flush is requested based on the understanding of fracture propagation during the execution based on the right detection of the fracturing events. The well-known Nolte-Smith method (1981) analyzes the treating pressure of a formation during pumping assuming all fracture events are referred to the initial fracture initiation point (regardless of the height covered by propagation during main fracture treatment). The net pressure is calculated based on the closure and plotted versus time for the start of the treatment on a log-log scale. Ayoub et al. (1992) introduced the pressure derivative of treating pressure analysis to be a good tool for fracture event detection.

ABSTRACT: Numerous studies have shown that approximately 50% of drill string failure modes are fatigue failure, and the initial defects in the drill string are one of the key factors affecting the fatigue life of the drill string. The influence of initial defects is often ignored in traditional fatigue life prediction model of drill strings, which leads to high prediction results of drill string life and underestimation of drill string failure risks. In this paper, considering the stress intensity factor, stress amplitude and crack geometry a method for predicting the fatigue life of drill string with and without initial defects in the whole section of extended reach well is established. Finally, the new model is applied used to for a case study, and the average stress and fatigue life of drill strings with and without initial defects under different defect depths, crack sizes, rotating speeds and weight on bit are calculated and compared. The results show that the fatigue life of drill string mainly depends on the defect depth and crack size. The larger the initial defect depth and crack size, the faster the fatigue life of drill string decreases. Weight on bit and rotating speed are secondary factors. With the increase of WOB and rotating speed, the stress intensity factor increases, the crack propagation rate increases, and the fatigue life of drill string decreases. The position of minimum fatigue life may be different under different parameters. The two minimum fatigue life positions predicted in this paper are 3188m and 4509m, respectively, which are weak points of fatigue life. The research results have important guiding significance for the optimization design and drilling safety control of extended reach wells. 1. INTRODUCTION With the needs of oil and gas exploration and development, the design of drilling wells has gradually changed from a single model such as vertical wells to complex structural models such as extended-reach wells and long horizontal wells. Compared with vertical wells, the horizontal section of complex structure wells increases, and problems such as high friction torque, frequent backing pressure, and buckling of pipe strings are more serious. Due to its own motion and downhole loads, drill strings often fail prematurely, which seriously affects the service life of the drill pipe and brings great risks and serious challenges to drilling and completion operations. Therefore, it is necessary to use mechanical methods to analyze the failure of the drilling tools and predict the fatigue life of the drill string, so as to better prevent and reduce the downhole fracture accidents of the drill string.

ABSTRACT: To maximize stimulated reservoir volume (SRV), an emerging fracturing technology, combined network fracturing technology is proposed and applied in Shengli shale oil reservoir. This technology aims to form a complex fracture network consisting of main fractures with higher conductivity and complex branched fractures by variable fluid-viscosity injection. In this paper, integrated with the finite element method (FEM) with the discrete fracture network (DFN) model, a complex fractures propagation model coupled with flow-stress-damage was established. The accuracy of the model was verified by the comparison with a two-dimensional analytical model. The effects of fracturing fluid viscosity on fracture propagation were simulated. Compared with conventional fracturing, variable viscosity injection procedure can improve the growth of main fractures and branch fractures, and then increase the complexity of the fracture network. Finally, a field application has been implemented in a typical shale oil well in Shengli Oilfield. The peak oil production of the well after fracturing treatment reached 171t/day, and the average oil production can maintain at about 28t/d after half a year of production, which significantly improves shale oil production. The novel fracturing technology proposed in this paper can provide a reference for the optimization of the fracturing fluid viscosity in combined network fracturing. 1. INTRODUCTION Jiyang Depression, located in the northeastern Shandong Province and the south eastern Bohai Bay Basin, is extremely rich in shale oil resources and has become one of the main development blocks of Shengli Oilfield. The shale oil reservoirs there have obvious laminated structures, which results in variable in-situ stress and interbedded layer properties. Staged fracturing in horizontal wells has played a prominent role in increasing production in this block. To maximize the stimulated reservoir volume, it cannot be satisfied with the fracturing only in fracturing layer. Due to the special structure of shale reservoirs, connecting multiple production layers through fracture growth in the height direction is the most effective way. To realize the purpose, some relevant measures have been tried such as increasing pumping rate as much as possible. However, even so, the height of the main fractures was much lower than the expected value. Therefore, we propose an emerging fracturing technology called combined network fracturing. The technology aims to form a complex fracture network consisting of main fractures with large height and complex branched fractures by variable viscosity injection procedure. Until now, there is few reports on fracture growth in layered shale oil formation under variable fluid viscosity. It is essential to study the propagation mechanism of hydraulic fractures under layered formation with bedding planes, so as to choose an optimal treatment scheme of combined network fracturing.

ABSTRACT: Overcoring is a common technique for measuring stresses in mining projects. Knowledge of the in-situ stress state is essential to ensure the stability of underground infrastructures as well as to assess the induced microseismic risk associated with deep mining operations. There are different types of overcoring probes. Some are bonded in the pilot hole with an epoxy resin and allow for 3D stress measurement (e.g. CSIRO-HI), and others are based solely on a mechanical coupling of the probe, but are limited to biaxial stress measurement (e.g. USBM). The need to glue the probe to obtain a 3D measurement limits the applicability of this technique to short boreholes because it is technically difficult to glue probes in deep boreholes. In any case, traditionally the data analysis is done only based on the final deformation obtained after overcoring. In this paper we propose to use the transient deformation response during overcoring to: (1) allow to evaluate the 3D stress field from a single biaxial overcoring measurement, and (2) add a quality control component by reproducing the entire overcoring response. The general principle of our approach is to simulate the transient response of overcoring by numerical elastic simulation. The principle of superposition is used to derive the responses for any set of parameters from a limited number of basic models and thus allows to limit the total number of model runs. Such approach allows for a systematic inversion procedure to be applied for determining the optimal parameter sets that best capture the transient response of the overcoring. This allows the estimation of a 3D stress tensor from biaxial measurements. It also allows to have a quality control on the measurements evaluating the quality of the fit between the model and the data. In this paper, we evaluate the robustness of the proposed approach by performing a systematic sensitivity analysis on the stress estimation from the inversion of transient overcoring data. We demonstrate the advantages of the approach but also its limitations. The preliminary results obtained in this study suggest that the transient overcoring response contains sufficient information for constraining efficiently the 3D stress tensor. The inversion must be performed using multiple starting point, and the mode of the obtained calibrated parameters is in close adequacy with expected values, while some outliers can be present in the calibrated set. Further work is required for confirming these encouraging results by testing of broader range of stress configurations and applying the method to actual field measurements.

ABSTRACT: Regardless of the porosity of the matrix, fractures have a crucial role in increasing permeability. In this article, the critical role that natural fractures may play in enhancing fluid flow characteristics is considered. An attempt to demonstrate the contribution of fractures on enhancing the permeability was done, assuming the genetic relationship between complex fracture systems at different scales. A multiscale-based statistical approach was adopted to compare hydraulic properties of two tight sandstone fields in a Cambro Ordovician reservoir situated in the Ahnet Basin, Algeria. The first field, situated in the Eastern region, denotes smaller fractures with three different orientations. In comparison, the second field, located in Western domain, is dominated by long faults, oriented N-S. However, the most predominant direction is NW-SE. In the first part, the connectivity of the networks was analyzed, and the results were plotted in a ternary diagram showing that the first field is characterized by a strong connectivity, probably due to the higher intensity of faults. Then, the dilation and shear tendency were displayed based on the current stress of the field. The outputs showed that fractures in the first field have a dilation and slip tendency higher which means that they are probably open and can participate in the creation of a fluid flow path. This is probably due to their orientation, parallel to the maximum horizontal stress. In the second part of this paper, naturally open fractures at the borehole scale were investigated and then compared to the seismic scale. Finally, the matching of the results at the two scales was studied. 1. INTRODUCTION A fractured reservoir consists of initially continuous deposits, which, as a result of the settlement, diagenesis, and deformation, have fractures. This type of reservoir would contain between 20% and 25% of the world’s available hydrocarbon reserves. Natural fracturing is a very important parameter in the assessment of an oil reservoir (Aoun et al., 2021). It can have several effects on production performance, both in primary recovery and in secondary or tertiary recovery. Traditional techniques used in the oil industry to characterize natural fracturing and its distribution at the reservoir level are insufficient. The seismic investigation provides a good visualization of the distribution of large-scale fracture zones. Well data can sometimes provide access to a satisfactory characterization of small-scale fracturing as long as the analysis of the images and the cores are done properly. On the other hand, intermediate-scale features (small faults, fractured corridors), undetectable by seismic tools and too much localized to be systematically characterized by the analysis of well data, remain very difficult to apprehend. However, their presence, detected at random by the progress of the drilling, proves to be decisive in controlling the hydrodynamic behavior of reservoirs. In this paper, we propose a qualitative and quantitative characterization of fracture networks.

ABSTRACT: This paper strives to model and validate annulus fluid and casing temperature profiles during wellbore warmback after fluid circulations. Modeling is based on published analytical methods. A research test well has been drilled to a predefined temperature target which can help validate the modeling results. Multiple live-streaming and memory tools are run to provide downhole temperature measurements during drilling, circulation, shut-in, cementing and post-drilling circulation/shut-in (warmback) operations. A permanent distributed fiber optic (FO) system, installed outside of the production casing, provides continuous downhole temperature measurements. One open-hole (OH) warmback and two cased-hole (CH) warmbacks were analyzed. The difference between modeled and measured temperature is within 3°F for the two cased-hole cases. With limited bottom hole temperature (BHT) measurements, the difference of the BHT is within 6°F for the open hole case. Dimensionless temperature studies show that after the dimensionless shut-in time reaches 9 for OH case and 20 for CH case (for the base-case formation thermal diffusivity) the difference between BHT and SFT (static formation temperature) reaches 10% of the difference between the wellbore temperature at the end of the circulation and the undisturbed SFT. For a given wellbore configurations and with 0.03 ft2/h (7.74e-7 m2/s) formation thermal diffusivity, this critical time corresponds to about 49 and 40 hours for the open hole and close hole cases, respectively. The models and results described in this paper can be applied to temperature log timing determination, geothermal well design, underground energy storage and geothermal recovery processes. 1. INTRODUCTION A good estimate of annulus fluid temperature in a wellbore plays an important role in drilling operation as well as in determining and possibly extending the operating range of various downhole tools. In geothermal drilling, for instance, most downhole tools involving electronic components become ineffective beyond about 175°C. A properly designed mud chiller or insulated drill pipes can extend the temperature limits. This requires a good thermal management approach. In this paper, we demonstrate the validity of some of the existing analytical models for wellbore thermal profile estimation by comparing them with measured data.

ABSTRACT: The Sanford Underground Research Facility (SURF, formerly known as DUSEL) is a dedicated underground scientific research facility located in Lead, South Dakota, at the former site of the Homestake gold mine. The SURF mission includes the construction of large underground cavern openings at depths of about 1500 meters to house large-scale physics experiments. A primary rock mechanics concern is the stability of these proposed large-diameter caverns (up to 165 meters) in a host rock which has been characterized to be orthotropic in the following conditions: (1) geometry, (2) in situ stress, (3) elastic properties, and (4) strength. Of the four dimensions of orthotropy, the third dimension (3) elasticity will be examined in this paper. The objective of this paper is to present the theoretical development and implementation of the equations that define two-and-three-dimensional orthotropic elasticity. The equations are developed based on simple laboratory testing configurations. The development of the three-dimensional equations of orthotropy is given in this paper. The method is validated with a numerical example and applied to a data set of test results performed on SURF rock samples to determine the orthotropic elastic constants and the principal orthotropy directions. 1. THREE-DIMENSIONAL MATHEMATICAL BACKGROUND Interest in anisotropic rock mass properties is demonstrated in the current literature [1]. In this initial study, laboratory measurements were made on samples taken from Homestake mine at known and preferred orientations each orthogonal to each other. Strains were measured on each face under a known and controlled state of three-dimensional stress. There were a total of 9 measurements on each cylindrical specimen (each modeled as a cubical specimen). This included 3 measurements on each face (2 normal strains and 1 shear strain) that were mutually perpendicular to each other. However, since each of the three normal strains were measured twice on complementary faces, there are only a total of six independent measurements on each sample. Since there are exactly six unknowns (3 elastic moduli and 3 angles of orientation), a unique solution for each sample can be found using the Solver tool in Microsoft Excel.

ABSTRACT: In the pursuit of net-zero carbon by the year 2050, the PETRONAS Group Research & Technology has executed CO2 storage studies incorporating laboratories results as well as with advanced simulation modelling prior to project execution for a case study in the year 2025. This paper is intended to highlight the advanced two-way coupled geomechanics-dynamic modelling workflow involving rock property updating and simultaneous history match for both reservoir simulation and geomechanics modelling. The purpose of this extensive coupled modelling workflow is to evaluate the potential challenges and risk of CO2 injection and storage including the impact of reservoir compaction towards final CO2 storage capacity, fault reactivation, caprock integrity and final injection limit. Advanced numerical coupled modelling for high porosity and highly compactable reservoir capturing the complex dynamic flow of the actual field conditions is challenging and requires a lot of attention to detail. Integration of the various disciplines such as geomechanics, reservoir engineering, geology and geophysics are crucial for the success of this project. This paper will also highlight the novel workflow, challenges and lessons learnt from the advanced coupled geomechanics dynamic modelling which can be applied in other similar projects. 1. INTRODUCTION The case study field was discovered in 1972 and production started in 1996. It is a carbonate gas field with about 350 ft of hydrocarbon interval and a thin oil rim of about 30 ft in thickness. The porosity ranges from 31 to 40% and extensive compaction has occurred with 700 psi pressure depletion throughout the gas production phase. Therefore, a Global Positioning System (GPS) sensor have been installed since the year 2000 to monitor the seabed subsidence due to field production. As the field has been depleted, it was identified as one of the potential CO2 storage sites which require an extensive subsurface evaluation before field injection.

ABSTRACT: Stick-slip is a solid constraint for shortening the drilling cycle and reducing the drilling cost, so it is crucial to establish a reliable stick-slip early warning model for drilling engineering. The existing early warning methods have low robustness and weak real-time performance, for which an LSTM-based stick-slip early warning model is proposed in this paper. Firstly, the triaxial acceleration is analyzed in the time and frequency domains, and its stationarity is tested. Then, the original data is denoised based on wavelet transform. Finally, the LSTM-based triaxial acceleration prediction model is proposed. The results show that when stick-slip occurs, the amplitude of triaxial acceleration vibration is larger, the power spectrum density is smaller than normal drilling, and there are apparent peaks. The triaxial acceleration is a stationary non-white noise sequence. The stick-slip early warning model developed in this paper can determine whether stick-slip will occur at least 3 minutes in advance, thus guiding operators to adjust drilling process parameters in time to mitigate the occurrence of stick-slip. 1. INTRODUCTION The friction between the drill string and borehole wall, drill bit, and rock is easy to cause stick-slip (Ozaki and Hashiguchi, 2010), which frequently occurs during drilling and seriously affects drilling aging. At present, stick-slip is mainly studied from mechanism model, signal analysis, and machine learning. The principle of the mechanism model is to use the drill string dynamics knowledge to learn the stability of the drill string system and the characteristics of stick-slip (Hong et al., 2016; Jia et al., 2018; Tian and Detournay, 2021). However, this method usually requires the assumption of harsh physical conditions, and its accuracy and reliability are low when the downhole environment becomes complicated. The signal analysis method focuses on identifying stick-slip by comparing the difference in drilling parameters between stick-slip and normal drilling (Teng et al., 2017; Huang et al., 2019). The machine learning algorithm has a strong nonlinear fitting ability and has been applied to stick-slip identification by some scholars. (Millan et al., 2019) established a stick-slip identification model based on SVM using surface drilling parameters. (Tang et al., 2021) established a stick-slip grade evaluation model based on XGBoost using near-bit triaxial acceleration data and Bayesian optimization. Although the signal analysis and machine learning methods can effectively identify stick-slip, the surface drilling parameters cannot truly reflect the working state of the bit (Zhu et al., 2014). The near-bit parameters that can genuinely reflect the working condition of the bit cannot be transmitted to the surface in real-time, which makes the existing identification methods have severe lag. If the near-bit parameters related to stick-slip can be predicted in advance, the working condition of the bit can be early identified, and operators can adjust the drilling parameters in time to avoid the occurrence of stick-slip. The Recurrent neural network (RNN) has unique advantages in time series prediction. (Meor et al., 2021) established hook load prediction model based on RNN, which effectively prevented the occurrence of the sticking. In this paper, we take advantage of the robust time series prediction of RNN to establish an LSTM-based stick-slip early warning model, which can effectively mitigate the occurrence of stick-slip during the drilling.

ABSTRACT: Microseismic monitoring has been developed to characterize fracture geometry. However, the results for fracture characterization can be incomplete due to interpretation and inversion methods that are limited by a lack of integrated geomechanical models. In the paper, a geomechanical microseismic simulator which includes natural fractures is developed to: (1) quantify the magnitude and capture the spatiotemporal distribution of induced microseismicity (MS), (2) evaluate the evolution of MS events along the vertical direction, (3) better account for the effect of noise, and (4) better interpret the MS data using a fully integrated 3-D geomechanical model. The results for spatiotemporal distribution of MS show that the locations of registered events tend to be consistent with those of planes of weakness prone to be reactivated due to failure. The vertical variation in MS events provide an efficient way to monitor vertical fracture growth. MS events generated by isolated fractures cause an over-estimation of the spatial extent of the fracture network that contributes to production. A similar effect is seen with seismic noise that can also lead to an over-estimation of the fracture network. Quantifying these over-estimations helps to improve mapping of the connected fracture network that is likely to contribute to production. 1. INTRODUCTION Hydraulic fracturing has been successfully employed in unconventional reservoirs in pursuit of increasing hydrocarbon production. Microseismic events are generally induced during hydraulic fracturing treatments. The monitoring of microseismic events provides an effective tool to estimate the geometry of the created hydraulic fractures and the reactivated natural fractures. A model that can enable us to improve fracture diagnostics and perform it more efficiently is developed and presented in this paper. Numerous studies have been conducted to investigate induced microseismic events during hydraulic fracturing operations over the past decades. These include, lab and field experiments, machine learning techniques, and numerical simulations.

ABSTRACT: This paper describes the swelling phenomenon that occurs in the Manikin tunnel, an ongoing diversion tunnel for the Manikin Dam Project in Kupang, Indonesia, driven through swelling clay underlain by the Bobonaro Formation. The Manikin tunnel experiences significant large deformation, resulting in substantial damage to its initial supporting structures. Three initial support systems are assessed through numerical simulation using the 2-D finite element method, namely: (1) the original design, (2) larger steel-rib + invert beam, and (3) the original design with forepoling + invert beam. To represent the swelling phenomenon, a zone of ground strength reduction is developed in the area surrounding the tunnel, and swelling pressure is exerted on the initial lining. This method is able to match the results of convergence monitoring. Numerical simulations show that the original initial support design results in large convergence up to 89 cm or 11.4% strain and thickness of plastic zone up to 3 m, but the proposed alternative support systems are able to control the convergence much better. For the initial support with larger steel rib + invert beam, the convergence is only 14 cm or 1.8% strain, and for the original support with forepoling + invert beam, the convergence is only 9 cm or 1.2% strain. This paper points out that the original support design with forepoling + invert beam yields the best supporting method as it results in the smallest horizontal and diagonal convergences. 1. INTRODUCTION Tunneling through swelling clay always poses a challenge in soft ground tunneling. The driven ground containing clay minerals tends to increase in volume when it comes into contact with water. The increase in volume, which is time-dependent, leads to inward movement of the tunnel perimeter. Large deformation, heaving of the tunnel floor, cracking of the sprayed shotcrete and poured concrete lining, and bending of the installed steel ribs are some of the many common manifestations of the swelling phenomenon. If remediating support measures are not performed effectively and in a timely manner, deformation may continue to increase with time, resulting in a complete collapse of the cavity.

In Petroleum Development Oman (PDO) mission that committed to empower employees with the needed capabilities and fuel innovation, efficiency and more importantly achieve and sustain a 100% Health, Safety and Environment (HSE), by transforming the way of handling HSE events by moving from reactive to proactive approach. Drilling operations represent a challenging environment due to human factors that prone focusing on operations mainly instead of safety of Personnel Protective Equipment (PPE). Surveillance cameras are installed in various locations in rig floor and contribute to security and safety. However, the current methods of video analytic in floor rigs are weak in the long-term sequence of nodes with missing and abnormal error value such nighttime, low illumination which causes poor images. In a proof-of-concept exercise, PDO has been provided the AI Solution to overcome all above limitation to develop AI Models based on drilling operation on rig floor. Consequently, this paper presents machine learning pipeline that is validated and evaluated the vendors Video AI detection of HSE violations of PPE and restricted zone access on the rig floor that shared video dataset. The pipeline can be described in two parts. Due to the complexity of the use case that usually difficult to be managed in-house, we propose a method to bring different algorithms solutions from different vendors where the evaluation is managed in-house. In this, we present a framework for video analytic evaluating safety operation drilling in floor rigs. This framework contains the data of video source that collected, annotations guidelines to support necessary data quantities for the best machine learning approaches, performance metrics, and tools that containing scoring baseline models to be able compute amazing performance output regarding annotated ground truth data. The benefit of this study was to address some challenges of video object analytic and tracking beyond evaluation framework that enables a significant comparison of Machine learning models, provides AI vendors with sufficient data for the exploration the automatic modeling approaches, encourages the incorporation evaluation the techniques with process development, and contributes valuable oil and gas drilling that will demonstrate very useful to Computer Vision (CV) research for next years.

Abstract Drilling through overburden shale often presents operational challenges, particularly when drilling high-angle wells. Chemical imbalance between the shale and the drilling fluid can lead to time-dependent wellbore instability resulting in stuck pipe; cavings; and, under extreme circumstances, loss of the well. This study provides a unique workflow combining a suite of laboratory measurements to evaluate rock-fluid interaction between shale and drilling fluids. The testing suite includes X-ray diffraction (XRD) for mineralogical composition; tight rock analysis (TRA) for fluid saturations and petrophysical properties; mercury injection capillary pressure (MICP) for pore throat radius analysis, pore water composition and water activity (aw) that is measured at ambient and elevated pressure using a new test system (patent pending); pressure penetration and membrane efficiency tests to evaluate pressure transmission through shale when exposed to drilling fluids; and modified thick-walled cylinder (mTWC) tests for screening potential adverse effects of drilling fluid on rock strength. Test results show how water activity measurements using synthetic brines can vary significantly from measurements made directly from the rock and under in-situ stress conditions. Water activity measurements made under stress correlate well with clay content and pore throat radius. From mTWC tests, the imbalance of aw can generate shale swelling and strength reduction. The pressure transmission tests show how the drilling fluids can plug the pores and reduce the pressure transmission rate to the formation. These data are instrumental in providing mitigating measures to avoid instability problems during drilling through overburden shales. Introduction Drilling high-angle development wells in shale can pose many operational risks requiring optimization of casing points, knowledge of safe mud weight profiles, and selection of the drilling fluid to counter rock-fluid interaction. Often the mud weight needs to be high enough to prevent shear collapse but low enough to not induce weak-bedding-plane failure (mechanical tensile failure) in the overburden. To determine the drilling window and optimum drilling mud weight for the well design, basic well logs and drilling reports are not enough to solve the problem alone; core measurements and advanced sonic are key ingredients to the wellbore stability model and subsequent predictions. Laboratory tests address both mechanical behavior through plane of weakness testing and modeling coupled with anisotropic characterization (Xi et al., 2020; Shaver et al., 2020) and evaluation of chemical shale interaction with drilling fluids to determine the effects of drilling time-dependent instability. This paper provides a novel laboratory testing approach to characterize shale time-dependent behavior to optimize drilling fluids used for shale formations.

Abstract Low primary recovery percentages (usually 10% or less) in unconventional reservoirs, such as the Three Forks Formation in the Williston Basin, mean that potentially billions of barrels of oil are left behind in the reservoirs. Gas enhanced oil recovery (EOR) pilot studies that were performed in the Three Forks Formation suggest that cyclic gas injection is a viable approach for enhancing oil recovery in unconventional reservoirs. Due to limited knowledge of the cyclic gas injection mechanisms and the interaction between the injected gases and Three Forks reservoir fluids, additional investigations are mandatory despite of the pilot studies and the published findings in the Three Forks Formation. This paper conducts a series of experiments on core samples from the Upper Three Forks (UTF) and Middle Three Forks (MTF) under different constraints. The parameters that affect the performance of the cyclic gas injection during the Huff and Puff (HnP) technique are analyzed, including soaking time in miscible and immiscible conditions, injection pressure, vapor-supercritical states, density change, gas type (CO2), Ethane (C2H6), Propane (C3H8), within these formations (Upper Three Forks, and Middle Three Forks), and the microscopic pore distribution effect on hydrocarbon transport for the production using the Nuclear Magnetic Resonance (NMR) approach. The findings indicated that the soaking time improved recovery factors significantly below and close to the CO2's minimum miscibility pressure (MMP), but its effectiveness decreased for the injection pressures over the MMP. At low injection pressures, propane (C3H8) was shown to be the most effective gas, followed by ethane (C2H6) and then carbon dioxide (CO2). Due to a significant shift in density, ethane (C2H6) and carbon dioxide (CO2) both performed better during increasing pressure. In contrast, increasing the injection pressure of propane (C3H8) above 6.89 MPa did not affect the performance since the density of propane at 6.89 MPa caused a negligible density change. Additionally, the NMR measurements conducted at the UTF indicated that in the first cycle of HnP, oil extraction was dominated by micropores, mesopores, and less by small pores. Increasing the HnP cycles, micropores will be the dominant source of oil production. However, in MTF, the mesopores were the dominant pore distributions, followed by small pores, which affect the micro oil mobilization during the HnP process. This work provides a new insight into understanding the mechanisms of gas HnP enhanced recovery in the Three Forks formation, which is of great significance for the efficient hydrocarbon exploitation and greenhouse gas utilization in the Three Forks.

Abstract Fracturing stimulation is an essential means of developing unconventional oil and gas fields, and borehole monitoring technology is crucial to evaluate the result of reservoir stimulation. This paper introduces a distributed fibre-optical demodulator based on optical frequency domain reflectance (OFDR) in detail. Then, combined with large-scale true triaxial fracturing physical simulation equipment, the laboratory experiments of fracture monitoring of concrete samples were carried out with bare optical fibre. The experimental results show that OFDR optical fibre sensing technology can monitor the change of strain evolution with high spatial resolution and high accuracy in fracture initiation, propagation, and closure in the whole-time domain. When the pumping displacement is increased from 15mL/min to 50mL/min, the hydraulic fracture width generated after the fracturing of the concrete sample increases by about twice. Hydraulic fracture monitoring by distributed optical fibre sensors under true triaxial fracturing can provide reference and guidance for the oilfield stimulation and fracture monitoring technology. Introduction Cross-well monitoring technology represented by microseism is one of the most mature evaluation methods after decades of development and practice (Hou et al., 2022a; Zhang et al., 2021). However, microseismic monitoring technology has many disadvantages, such as difficult interpretation, poor timeliness, many noise points, and high cost (Hou et al., 2019a; Hou et al., 2019b). It cannot be monitored in the same well, which cannot meet the needs of industrial reservoir stimulation and evaluation. In-well monitoring technology based on optical fibre has entered the vision of oilfield engineers.

Abstract The objective of this paper is to highlight a new machine learning application to predict a synthetic caliper log using other available Logging While Drilling (LWD) well logs. LWD logs and wireline (WL) mechanical caliper logs for 17 tight gas wells, with more than 120,000 depth data points, were used to train a machine learning model. LWD logs included gamma ray, sonic, density, azimuthal density, porosity, photoelectric log, and mineralogy. The LWD logs were used as main input parameters in the model together with the maximum hole dimeter (Cmax) from wireline data. The model output being the synthetic maximum borehole diameter (Cmax_P) was compared with the measured caliper log. The model was trained with various machine learning algorithms including ensemble algorithms such as XGBoost and recurrent neural network (RNN). In the training process, Leave-One-Out method was implemented where 16 wells were used for training to predict the maximum borehole diameter in the remaining blind well. The results of current dataset showed good prediction accuracy with an average absolute percentage error of less than 6%. In addition, we demonstrated incorporating a physical feature related to geological layering by training the RNN with a window of multiple depth points, which clearly resulted in a predicted caliper curve that was significantly less noisy and had closer characteristics to the measured caliper curve. Introduction In multi-stage fracturing well completions, running a wireline mechanical caliper log is critical to obtain reliable measurements of borehole geometry along the lateral to identity packers’ placement depth for achieving adequate zonal isolation between successive fracturing stages. However, in many instances, wireline caliper logs cannot be run due to borehole conditions and drilling challenges. In such cases, various logging-while-drilling (LWD) well logs could be utilized to derive a synthetic caliper log.

Abstract The anticipated prevalence of salt caverns for hydrogen storage makes it increasingly important to establish good numerical modelling techniques to simulate cavern behaviour. This involves many modelling aspects to be addressed including a proper representation of the particular material characteristics of salt and a recognition of the importance of cavern geometry. In this paper we demonstrate a 3-D finite element modelling methodology for simulating salt caverns under the type of cyclic loading expected from seasonal hydrogen production and retrieval. 3-D modelling offers the possibility to represent more complex cavern geometry than is usually represented in such work. The simulations represent generic scenarios but are used to investigate the effect of cavern geometry and variations in model size and boundary conditions. We make use of the recent constitutive model advanced by Reedlunn et al., 2022 which includes an allowance for pressure solution effects contributing to creep, and show that this can have a significant effect on cavern closure. Introduction Hydrogen is widely expected to play a major part in the migration away from a carbon-based energy economy and demand for high volume storage solutions is likely to grow considerably in the near future. The use of salt caverns is among the storage methods attracting the most attention. Salt caverns are subterranean voids in domal or bedded salt formations, usually created artificially by a process of leaching. They are well suited for hydrogen storage because they can offer large capacity, rapid injection/withdrawal rates, safety advantages and long term cost effectiveness. In addition the technology is proven – such caverns being widely used over many years for the storage of other substances and more recently in limited numbers for hydrogen.

Abstract Hydraulic fracture initiation can be a challenging issue for fracturing deep and tight gas reservoirs, which generally requires a high breakdown pressure for clustered perforation hydraulic fracturing treatment. Oriented perforation represents a potential solution to alleviate this issue, which can not only lower breakdown pressure but also deliver a better oriented fracture geometry. In this paper, we present a new strategy to tackle this issue, which includes a framework to calculate the breakdown pressure, optimum perforation direction, and a new perforation cluster layout design. The optimum perforation direction is defined as the one, along which hydraulic fractures can be initiated with the lowest breakdown pressure for a perforation cluster. It can be used to control the perforation device rotating and fired at the right direction in subsurface. Further we present a new perforation cluster layout design, which can alleviate the near wellbore fracture tortuosity and deliver a better fracture initiation when it is aligned along the optimum perforation direction in the subsurface. The two parts of the strategy working together, fracture initiation from a perforation cluster can be achieved a lot of easy than using the conventional perforation method. This new perforation strategy can further alleviate the near wellbore fracture tortuosity, minimize fluid flow restriction and reduce pressure friction loss during hydraulic fracturing treatment. Otherwise multiple and reoriented nonplanar fractures originated from the wellbore perforation cluster likely lead to a premature screen-out, which can negatively impact fluid injection to achieve a desired stimulation performance. Hydraulic fracturing treatment in deep and tight gas reservoirs can be improved through the following actions: calculating breakdown pressure and optimum perforation direction, using new perforation cluster layout design, and aligning the perforation cluster in the optimal direction in subsurface.

Abstract Predicting the nature and extent of deformation adjacent to wellbores can be critical for successful subsurface operations. The ability to capture the onset and evolution of failure can permit more efficient operations and circumvent or minimize the effects of well-known operational issues such as wellbore instability and sand production. In this paper, the behaviour of porous sandstones is investigated through replication of experimental testing conducted by Haimson (2004). In this work the deformation near the excavated section for highly porous sandstones was documented and analyzed, with contrasting deformational styles observed that are tentatively attributed to mineral composition. The requirements for predicting these styles are discussed and presented within a novel three-field modelling framework that incorporates a sophisticated constitutive model. Application of the workflow and results for breakout and sand control studies is discussed, along with potential future extensions to the capabilities of the constitutive model. Introduction Instability of subsurface excavations is critical and can pose serious problems affecting the timing and success of a project. Prediction of such instabilities has long been recognised as a key factor in many industries. Understanding the failure mechanisms is vital for the optimisation of well production as instabilities affect drilling efficiency, resulting in lost circulation, breakouts, or hole closure and even in loss of the open-hole section due to stuck and damaged drill pipe (Lang et al., 2011). Nevertheless, such instabilities are useful for informing on stress directions and magnitudes (Haimson and Song, 1993). Borehole logging has been long used to estimate stress directions, based on the location of the breakouts around the well (Brudy et al., 1997; Zoback et al, 2003; Kingdon et al., 2016). In addition, several studies have suggested that the characteristics and dimensions of the breakouts, if properly measured, can also inform on the magnitudes of far-field stresses.

Abstract The giant Rumaila oilfield in south Iraq has been plagued by a number of wellbore instabilities. The shaley formations in this field pose the greatest challenges to drilling operations, accounting for approximately 90% of the problems. Stuck pipe, tight hole, and borehole collapse are examples of the incidents commonly encountered even while drilling vertical wells. The main objectives of this study were to generate a mud weight window cube for different trajectory scenarios by examining the impact of depletion on field performance and drilling integrity for making life-of-reservoir decisions. The derived mechanical properties were taken from their respective 1D mechanical earth models (MEM) by utilizing the available mechanical core test data and populating in 3D space. The final 3D MEM has been calibrated against field observations. This paper presents a well planning tool for translating the geomechanical modeling results to operational parameters, and in so doing, informing well trajectory planning and optimization. Introduction Reservoir geomechanics play a vitally important role in minimizing drilling activity costs and informing field development planning. Comprehensive geomechanical models (1D, 3D and 4D) have been built in the Rumaila Field based on a wide array of inputs taken from 14 wells distributed across the field. The analysis examined the stress changes in the main reservoirs—namely: Mishrif and Zubair Main Pay—and addressed the instability issues in all Rumaila formations encountered while drilling, by using the available openhole logs, core mechanical test data, production data, and pressure data. The main objectives of this study were to build a fieldscale geomechanical model with a view to assessing the impact of production-induced stress changes on field performance and generating mud weight cubes at different timesteps (Al-Asadi 2021).

Abstract Confined Compressive Strength (CCS) offers a more accurate indication of rock hardness and rock formation drillability, which is useful in optimizing the drilling operation. PhiDrillSim is a machine learning app that predicts the CCS using neural network techniques. The goal is to predict the Confined compressive Strength using the Neural network technique based on the operation dataset, which will be used to train the neural network model. A specific operation dataset will be provided for the training of the model in the app. It will predict the CCS model of the rock formation and compare it with the actual CCS collected. Preliminary results show that the accuracy of the predicted CCS values is consistent with the CCS calculations using the log data method. There are various methods of calculating the CCS of the formation, with varying degrees of cost and difficulty. Furthermore, the accuracy of CCS measurements directly affects the drilling cost of operations, affecting drill-string durability and operational time. This paper explores the accuracy of the PhiDrillSim App in comparison with a log data method in calculating and predicting the formation of CCS. CCS Description Rock strength is essential in the drilling process. Confined Compressive Strength (CCS) is a geomechanical rock property that indicates the rock strength when confined to some medium. (Fabian, 1994). Since UCS is widely used, the classification of rock formations based on UCS is readily available. Moreover, the estimation of rock strength classification is based on UCS. CCS then will be related to UCS using the equation proposed by Caicedo et al., 2005.

Abstract As the low permeability and porosity, some severe problems including rapid production decline and low recovery ratio usually occur in Jimsar Shale Oil Field. Re-fracturing of horizontal wells is a good treatment to improve oil production and recovery ratio by enlarging the contact area between the wellbore and reservoir. Therefore, the field tests of horizontal well re-fracturing were carried out in Jimsar shale oil reservoir. However, it varied in effect. In this paper, based on the engineering parameters of primary fracturing, a fuzzy evaluation model was established firstly to quantify the potentiality of candidate horizontal wells for re-fracturing. For the test wells, a production history match was completed using reservoir numerical simulation method and the oil saturation before re-fracturing was obtained. By comparing the location of high-saturation area and new perforation, rationality of re-fracturing stages selection is determined. Finally, comprehensively using fracturing pressure and microseismic data, the initiation and propagation areas re-fractured was obtained, which showed the location of new fractures. Above all, the reason for poor re-fracturing effect is analyzed. The results show that quantitative index of each test well ranks low among the candidate wells, which means the test wells have the low potentiality to be re-fractured. For the test wells, numerical simulation results show that new perforations of re-fracturing are not located in high-oil-saturation area. The fracturing pressure of re-fracturing stages is generally smaller than primary fracturing, and the microseismic event locates in highly depleted area, which means large quantities of fluid flow into primary fractures and few new fractures are created during re-fracturing.

Abstract Real-time estimation of the formation pressure can enhance the drilling operations in terms of non-productive time, costs, and safety. In the literature, the known methods for formation gradient prediction are derived from logging or a combination of selected drilling data and logging. The objective of this paper is to use random forest (RF) to develop a predictive model for real-time pore pressure gradient using surface drilling parameters. The used inputs were pump rate (PR), standpipe pressure (SPP), rate of penetration (ROP) and rotary speed (RS). A field data set was used to develop the prediction model. Another data set was used for validating the developed model. The proposed model estimated the pressure gradient with a correlation coefficient (R) of 0.99 and 0.98 for training and testing. The root mean squared error (RMSE) was around 0.01 and 0.014 psi/ft for training and testing. In addition, the average absolute percentage error (AAPE) was 0.96% and 1.66% for training and testing. Introduction Formation pressure is the one exerted by the fluids contained inside the pores of formations. The normal pressure gradient ranges between 0.433 psi/ft and around 0.465 psi/ft (Bourgoyne et al., 1986). Abnormal pressure is used for any deviation from the normal pressure trend that can be either supernormal or subnormal (Mouchet, J.P., and Mitchell, 1989).

Abstract Supercritical carbon dioxide fracturing technology, as the main representative of water free fracturing technology, has unique advantages and broad application prospects in the development of shale oil and gas reservoirs. Supercritical carbon dioxide fracturing technology has low damage to the reservoir, no residue, and the fracturing fluid can flow back quickly, which is particularly suitable for the stimulation of shale oil reservoirs. It also injects carbon dioxide into the ground to reduce environmental pressure. However, as a new fracturing technology, the research on the fluid loss mechanism of supercritical carbon dioxide fracturing is not perfect. For this reason, based on the fluid solid coupling of porous media, this paper establishes the fluid loss model of supercritical carbon dioxide fracturing fluid in shale reservoir. The research results show that supercritical carbon dioxide fracturing fluid is greatly affected by temperature and pressure. The greater the viscosity of fracturing fluid during injection, the greater the resistance of fluid in the formation, and the slower the fluid loss rate. contributions of the work. Introduction With the progress of oil and gas field development technology, the development of low permeability and tight shale oil and gas resources has been paid more and more attention(Holditch, 2013). The decision-making power of the future energy market mainly depends on the resource potential and development degree of unconventional oil and gas. Nowadays, unconventional oil and gas resources development technologies and transformation measures represented by shale oil and gas are gradually maturing(Cui, 2019a , Cui, 2019b). Among these technologies, carbon dioxide fracturing technology has unique advantages in the stimulation and development of shale oil and gas reservoirs(Monjezi et al., 2020 , Rod et al., 2020 , Nianyin et al., 2021b , Nianyin et al., 2021a), including that the fracturing fluid does not contain water and has strong applicability to water sensitive formations(Liu et al., 2014).

Abstract Laminated shale reserves various natural weak planes involving some bedding planes, natural fractures and mineral dykes. The obvious phenomenon of the interactions between hydraulic fractures and bedding weak planes were observed involving arrest, crossing, and diversion in previous works. Moreover, the bedding angles, cement mineral compositions of natural weak planes, and net pressure of hydraulic fracture were considered as the primary factors to determine the type of interaction. However, the rock failure modes and characterization of weak planes from micromechanics has been yet addressed. In this paper, a Particle Flow Code (PFC) model on natural weak planes of laminated shale was proposed by considering micromechanical properties including the cohesive strength, stiffness, elastic modulus, and friction angle. The PFC model was validated by the three-point bending tests on a typical laminated shale. The influence of weak plane angles, elastic modulus, and strength of weak planes on tensile fracture propagation were obtained. Their interaction types and dominant failure mode from tensile to shear were analyzed. It concludes that fractures divert in the inclined angles and low strength of natural weak planes, crossing occurs in the opposite case. Introduction Shale oil and gas formation normally reserves various natural weak planes involving the weak bedding planes, natural fractures and mineral dykes. It is evident that the natural weak planes affect hydraulic fracture geometry. The obvious phenomenon of the interactions between hydraulic fractures and bedding weak planes were observed involving arrest, crossing, and diversion in previous works. Moreover, the bedding angles, cement mineral compositions of natural weak planes, and net pressure of hydraulic fracture were considered as the primary factors to determine the type of interaction. However, the rock failure modes and characterization of weak planes from micromechanics has been yet addressed.

Abstract Jurassic to Eocene sedimentary rocks in central Arabia have been deformed by faulting and jointing. We measured these structures in the field. Paleostress directions from these data demonstrate that successive extensional events occurred. Introduction The effects on platforms of distal tectonic events can be used to study the deformation in front of mountain belts (Bergerat, 1987) or between more highly deformed regions (Bergerat et al., 1992). These studies may yield clues to the directions of plate motion which may be difficult to decipher within the mountain belts due to the complexity of the deformation, or they may aid in determining the deformation process. Unlike regions previously studied in this context, the Arabian Platform is not just in front of a mountain belt such as the West European Platform (Bergerat, 1987) nor trapped between deformed zones such as the Colorado Plateau (Bergerat et al., 1992), but is the foreland of the Bitlis/Zagros/Oman deformation belt and is also near the Red Sea/Gulf of Aden which have been forming as small ocean basins simultaneously with convergence in the mountain belt. Previous workers have argued that the Red Sea/Gulf of Aden could not have formed as a "passive" rift related to the formation of the Bitlis/Zagros belt because the Arabian Platform is undeformed. In this paper, we show that the central Arabian platform has indeed been deformed and we link its deformation to tectonic events occurring on the margins of the Arabian plate supporting models for a passive origin of the Red Sea/Gulf of Aden (Gordon and Hempton, 1986; Hempton, 1987; Bohannon et al., 1989).

Abstract Tunnels offer considerable benefits over other alternative forms of transportation infrastructure. For example, in contrast to highways, tunnels ensure unobstructed land above remains available for all forms of land-use that can present notable economic, social, and environmental advantages. This feature is important in highly urbanized areas where usable land is scarce and acquiring land can put high financial pressure on available budgets. Tunnelling uncertainty is the main contributor to cost overruns which are mainly due to geological uncertainity. Therefore, accurate prediction of geological characteristics can lead to higher efficiency of tunnelling projects and prevent any cost or time overruns. In this paper, a random forest (RF) approach is utilized to model underground lithology using 65 boreholes along a tunnel project. In order to acquire best hyper parameters for the RF model a random search optimization algorithm is used. Also, different intervals along the boreholes are used to extract the lithology to find the sensitivity of the model to different interval length. The results show that the proposed model can predict the lithology with 86 percent accuracy. The model was successful in prediction of lithology type and their order along the boreholes in a case study example. Introduction Tunnels offer considerable benefits over other alternative forms of transportation infrastructure in terms of land-use and planning. This feature allows for greater flexibility in use of lands in highly urbanized areas where usable land is scarce and acquiring land can put high financial pressure on available budgets. Tunnelling uncertainty is the main contributor to cost over runs the which is mainly due to geological uncertainity. Therefore, accurate prediction of geological characteristics can lead to higher efficiency of tunnelling projects and prevent any cost or time overruns (Yan-lin et al. 2011; Hossin and Sulaiman 2015; Zhang and Zhu 2018).

Abstract Sand production is one of the major problems in many oil and gas assets around the world. Uncontrollable sand production can affect hydrocarbon recovery and increase operational costs. This paper aims to develop a classification approach to suggest the optimal sand control method using machine learning algorithms. Four different models have been used, namely K-Nearest Neighbors, Support Vector Machine, Random Forest and Decision Tree. After extensive exploratory data analysis, nine parameters were included in the model: Sorting coefficient D10/D95, Mass fraction smaller than 44 micron, Well deviation angle through the pay zone, Pay-zone true vertical thickness, Bottom hole pressure, Maximum oil rate, Maximum gas rate, Permeability, Well type. By comparing the different models in this study Random Forest classifier achieved the highest evaluation metrics: f1-score of 0.9568, precision of 0.9580, and recall of 0.9568 respectively. These results combined with the confusion matrix to assess the model performance have shown that up to a certain level machine learning methods can ensure the adequate completion for the candidate well. The proposed work turns out to be a potential approach that rises to the level of a decision support tool and thus can help engineers set the right completion option. Introduction Sand production has always been one of the major concerns for the oil and gas industry. It is the result of the migration of failed sand grains because of the drag forces caused by fluids flow from an unconsolidated reservoir. Generally, this phenomenon leads to technical problems such as erosion of downhole equipment and surface facilities, production loss, well access obstruction, and economic effects represented by the additional cost of sand disposal. Sand control is, therefore, necessary to mitigate the effect of sand production on hydrocarbon wells. Judhan (2016) defined sand control as all the techniques that allow hydrocarbons production without sand grains production in the wellbore. Sand control consist of two methods: passive and active. Passive sand control methods are generally used to reduce sand during the first stage of production when the sanding rate is low, as this latter gradually increase, active sand control will be required.

Abstract An in-depth description of the objectives of rich gas cyclic huff 'n' puff in the Three Forks of the Williston Basin, as well as the design, field operations, production, pressure, and other surveillance results, is provided in this case study. To summarize, the overall purpose of the enhanced oil recovery (EOR) and CO2 storage, a case study, was to discover important performance indicators of cyclic gas injection, which would then be used to construct a commercial field scale EOR method. To achieve these objectives, a fully designed well in the Three Forks tight oil play was tested vertically and laterally for the potential to confine gas inside the target intervals and create pressure to induce a miscible displacement process. In this paper, a detailed reservoir model was built to investigate the CO2 huff-and-puff process for enhancing oil recovery (EOR), and to understand the impact of different parameters on the CO2 EOR performance in different scenarios. The model includes an area of well-characterized Three Forks formation and fracture characteristics with actual production data from the field for accurate history matching and forecasts. The effects of cycle number, injection and soaking period, permeability, reservoir bottom hole pressure, and CO2 molecular diffusion are investigated to optimize the reservoir's CO2 EOR performance. The findings suggest that CO2 diffusion is essential in enhancing oil recovery from tight oil reservoirs as the recovery factor (RF) without diffusion was 12%, including the diffusion coefficient the RF increased by 4%. Also, the bottom hole pressure significantly impacts the recovery factory. Furthermore, the CO2 huff-n-puff technique is more beneficial in tight oil formations with high permeability and more CO2 injected in a short soaking period. Significant design and operational efficiencies were discovered during this well simulation for gas injection test in the Three Forks play that will benefit an economically feasible fieldscale project. For example, the schedule of injection and soaking period permitted gas injection operations to be carried out without modifying wells' operation pressure. Cycling in a short soaking time makes it possible to perform injection/production conversions at the lowest possible cost. It is also possible that including the diffusion coefficient in the simulation will have better gas injection conformity across the horizontal completed intervals.

Abstract Effective geomechanical analysis requires a thorough understanding of the complexities of the formations drilled, such as stress-induced anisotropy, intrinsic anisotropy, azimuthal heterogeneity, drilling induced and natural fractures, and/or borehole damage. The identification and classification of these features can be complex, particularly when multiple different types are present together. The conventional sonic tools can struggle to differentiate these effects when more than one is present and often are lacking in the capability needed to clearly resolve them mainly because of the limited spatial resolution associated with the probing sonic frequencies. A new logging-while-drilling (LWD) dual ultrasonic tool has been developed, that provides high-resolution, full-azimuth, ultrasonic compressional and shear (P&S) slowness images together with ultrasonic borehole images and caliper that can be used to help address this formation complexity on multiple scales and so to improve geomechanical models and analysis. In this paper, we study feasibility of classifying formation geomechanical features, such as intrinsic anisotropy, stress-induced anisotropy, and azimuthal heterogeneity, using the ultrasonic P&S slowness from the LWD dual ultrasonic tool, and discuss conditions when such classification is expected to be successful and when more integrated approach is needed to address complexity of formations. Introduction Understanding the complexity of formation mechanical properties is very important for effective geomechanical analysis, such as the optimal design of hydraulic fracturing or wellbore stability analysis for safe and cost-effective drilling. Conventionally, standard sonic logging has been used to provide key acoustics measurements to characterize the formation mechanical properties axially, azimuthally, and radially (Pistre et al., 2005). These measurements are made at sonic frequencies, which results in an intrinsic limitation for resolving layers smaller than 1-ft thickness, because of the probing wavelength at these operating frequencies. A recently developed LWD dual ultrasonic tool demonstrated the ability to deliver P&S slowness measurements and images that resolve inch-scale bedding (Blyth et al., 2021). The P&S slownesses measured at ultrasonic frequencies deliver measurements with 2-in vertical resolution and in 16 azimuthal sectors around the wellbore. The tool also provides borehole images and calipers with ultrasonic pulse-echo measurements. P&S images from the field test data showed evidence that both intrinsic and stress-induced anisotropy can be revealed using LWD dual ultrasonic data at a similar fine resolution scale.

Abstract Changes in the magnitude of the effective stresses due to hydrocarbon production will lead to formation failure in the reservoir rock and around the wellbore. The failure around a wellbore and within the reservoir formation assumes that rock can fail due to mechanical damage within the formation. This damage can be defined as an irreversible dissipative. This study aims to evaluate the damage mechanics due to applied horizontal and vertical forces due to reservoir depletion. Formation mechanical properties, the magnitude of the axial and lateral stresses, and fluid properties will characterize the degree of damage mechanics. Such damage can be described on a macroscopic scale via a damage variable. The damage variable is equal to the increase in the porosity of the formation due to the creation of microcracks because of stress concentration around the wellbore. It is also assumed that damage is linearly related to the material's amount of plastic shear strain. The damage degree, including the debris's size and shape, depends on the grain cementation, fluid flow velocity, and the magnitude of the acting forces. The mechanism of damage can be sand grain sliding or crashing. The resultant solid production while hydrocarbon production or formation damage depends on the size of the debris. This innovative study will be used as a guideline for hydrocarbon production and injection strategies to avoid reducing porosity and Permeability. Introduction The yielded zones will be characterized to evaluate the wellbore stability during drilling and production due to stress redistribution, strain concentration, and fluid flow. This modeling will improve the borehole completion and stimulation and avoid wellbore blockage during hydrocarbon production. The knowledge of failure mechanics usually determines the type of failure criterion used in wellbore stability modeling. This paper used the Drucker-Prager criteria for wellbore stability assessment.

Abstract Fengxi structure in Qaidam basin is a low porosity and ultra-low permeability reservoir mainly composed of algal limestone on the land of China. Algal limestone is thin and distributed dispersedly. There are problems such as inaccurate dessert identification and large difference in single well production during fracturing. In this paper, reservoir analysis is carried out through cutting electron microscope scanning experiment and core test experiment to obtain and correct various parameters characterizing geological and engineering desserts. A prediction model of algal limestone reservoir fracturing desserts is established by combining the advantages and disadvantages solution distance method (TOPSIS) with the analytic hierarchy process (AHP), and dessert point grades are classified. According to the calculation results, Fengxi Block is generally at the level of Class III and IV desserts, and the artificial fractures are mainly multi fractures near the well and single fractures. Compared with adjacent wells, this method reduces the construction pressure by 10.1% and increases the production by 49.7% after well selection and formation selection, realizing the purpose of precise stimulation of reservoir desserts, and providing a new idea for efficient development of algal limestone reservoirs in Qaidam Basin. Optimization of Dessert Attribute Parameters There are many influencing parameters involved in the identification of fracturing desserts, including geological attributes and engineering attributes (Huang J.L, 2012). In order to accurately screen out the attribute parameters representing dessert, the scoring method is adopted to quantify the score of each attribute one by one, and the attribute parameter with the highest score is selected as the basis for dessert recognition. Attribute scoring methods include accuracy scoring, representation range scoring, and necessity scoring (Han F.P.et al,2019). In the accuracy score, the accuracy of the parameters obtained by the direct measurement method is high, and the score is 3 points; The accuracy of parameters obtained through inversion of relevant data is medium, and the score is 2 points; The score of other data with poor accuracy is 1 point. In the score of characterization range, the parameter that can represent the continuous well section is scored as 2 points, and the parameter that can only represent the specific depth is scored as 1 point. In the necessity score, the parameter with high importance is scored as 2 points, and the parameter with low importance is scored as 1 point.

Abstract Knowledge of in-situ stress magnitudes is important in exploring and developing conventional and unconventional oil and gas resources. Whilst the vertical and minimum horizontal stresses may be derived relatively straight forward, the magnitude of maximum horizontal stress cannot be measured directly and must be indirectly estimated. In this paper, a new semi-analytical poroelastic solution is developed for stress and pore pressure distributions surrounding a borehole with a known breakout geometry. The entire geometry of the stabilized borehole breakout, not just breakout width, is utilized for estimating the maximum horizontal stress magnitude. Breakout tip strength is evaluated by considering several mechanisms perceived to be responsible for breakout stabilization. The maximum horizontal stress magnitude is then estimated from the equilibrium condition of stress and rock strength at the breakout tip which attracts the highest stress concentration. The newly derived maximum horizontal stress estimation model is validated based on several sets of laboratory borehole breakout experiments conducted under three-dimensional stress conditions sourced from literature. Comparison between the model prediction and the experimental results showed that the estimated maximum horizontal stress has a good approximation to the maximum horizontal stress magnitude applied and showed a significant improvement over the existing method. Introduction Knowledge of the state of in-situ stresses is important in exploring and developing conventional and unconventional oil and gas resources. It plays a critical role in analyzing wellbore stability, sand/solids production, well trajectory optimization, perforation orientation and hydraulic fracture stimulation. For a petroleum basin with a relatively flat surface topology, the in-situ stress state may be defined by a vertical and two horizonal stresses and their orientations. Whilst the magnitudes of the vertical and minimum horizontal stresses may be derived relatively straight forward, the magnitude of the maximum horizontal stress cannot be measured directly and must be indirectly estimated.

Abstract Rock salt is a very complex material. Simulation of the non-linear and time-dependent mechanical behavior of salt caverns requires advanced constitutive models, relevant sets of parameters and accurate numerical computations. No well-known software packages were designed initially for salt caverns; they had to be adapted by the end user due to the unusual behavior of salt compared to other rocks. Most of the time, cavern thermodynamics, salt geomechanics and hydraulics cannot be calculated simultaneously. Some software packages are limited only to rock/soil mechanics and thermal computations —they include no cavern thermodynamics. However, coupling cavern thermodynamics and rock mechanics is essential when considering problems such as fast cycling in a gas cavern, the storage of hydrogen or compressed air, or for modeling of the long-term behavior of caverns. A case-by-case study must be performed for all new projects, taking into account relevant creep and also considering sets of parameters that were calibrated accurately in the laboratory — or better, from on-site tests performed in an existing borehole or cavern. This paper introduces the main features of salt-rock mechanics and salt-cavern thermodynamics. A simple example of a cycled hydrogen cavern experiencing a blowout is presented. Introduction Storage of gaseous and liquid hydrocarbons in salt caverns is a mature technology. More than 2000 caverns are operated worldwide. Storage of electricity as compressed air in salt caverns (CAES) is possible; two caverns have been operated for this purpose since the 1970s, and a couple of new projects are under development (Koopmans et al., 2022). There also are many ongoing projects related to hydrogen storage (Fig. 1). Salt caverns initially were designed, created and operated using very limited modeling tools. The complexity of rock-salt behavior and of cavern thermodynamics appeared gradually.

Abstract Increasing global demand for gas has led to a larger focus on production from deep gas HP/HT reservoirs. The case study presents an offshore field under current development with several vertical wells that confirmed varying reservoir extent, successful stimulation, and productivity. The target formation is a naturally fractured HP/HT low permeability clastic reservoir with lateral and vertical reservoir quality variations. Measured stress rotation within the structure and large minimum stress variations across different reservoir intervals support the presence of a complex stress environment where the development of a predictive 1D Mechanical Earth Model (1DMEM) becomes challenging. The combination of a variable stress dependent permeability within an altered stress field introduces uncertainty in the estimation of fracture geometry and hurdles its optimization. The paper presents a multi-frac completion strategy to be implemented in newly drilled development wells by utilizing state-of-the-art hydraulic fracturing optimization workflows driven by an integrated multidisciplinary approach. Introduction The offshore field presented here is located west of Abu Dhabi city. The subsurface structure was first identified in 1966 and is part of a regional N-S extending structural trend with other nearby fields. The targeted formation is a deep naturally fractured tight gas clastic reservoir that presents lateral and vertical reservoir quality variations. It possesses three different reservoir units (A, B and C) with diverse petrophysical and mechanical properties. The new development considers cased and cemented s-shaped wells with a dedicated 4 ½” frac string to pump stimulation treatments at high rates. The “plug and perf” completion methodology was selected since this allows flexibility given the initial uncertainty in the hydraulic fracture growth and to properly evaluate intervals production performance.

Abstract An accurate prediction of elastic parameters is crucial for predicting minimum horizontal stress in wellbore stability, drilling design of horizontal borehole azimuth and hydraulic fracturing in petroleum engineering. For a transversely isotropic shale formation, the vertical and horizontal mechanical properties can be obtained from five independent elastic stiffnesses C11, C33, C44, C66 and C13, which also are the necessary parameters for horizontal stresses estimation. Among these stiffness coefficients, C33 and C44 can be obtained from the P- and S-wave velocities while C66 is calculated from the Stoneley wave velocity if there is. The other two elastic stiffness C11 and C13 have to be obtained from the empirical model, such as ANNIE model, M-ANNIE model, M-ANNIE2 model and V-reg model. However, the adaptability and accuracy of the above models to a formation are very different from each other, which need optimization analysis for a specific formation. The objective of this paper is to evaluate the discreteness of stiffness coefficients of the above four empirical models by applying datasets of the ultrasonic velocities of Wufeng–Longmaxi shale of the Sichuan Basin in China, for finding a suitable model of this shale formation for predicting horizontal stress. These four models are divided into two types by whether or not there is Stoneley wave in model, which is group 1 including ANNIE model and M-ANNIE model with Stoneley wave, and group 2 including M-ANNIE2 and V-reg model which lack for Stoneley wave. The results show that the elastic parameters obtained from M-ANNIE model has the smallest deviation with the measured results in group 1. While the elastic parameters calculated by V-reg model makes lower deviation compared to M-ANNIE2 in group 2. But for both groups, the goodness-of-fit of V-reg model is better than other models. Finally, the two models M-ANNIE2 and V-reg are used to a field log example missing Stoneley wave. The results of minimum horizontal stress show that the average error between calculated solution from V-reg model and measured values is less than 10%, which can reflects the actual formation more accurately and exhibit good application potential for drilling and fracturing.