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Kim, Guan Woo, Tae Hong Kim, Jiho Lee, and Kun Sang Lee. "Coupled Geomechanical-Flow Assessment of CO2 Leakage through Heterogeneous Caprock during CCS." Advances in Civil Engineering 2018 (2018): 1–13. http://dx.doi.org/10.1155/2018/1474320.
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The viability of carbon capture sequestration (CCS) is dependent on the secure storage of CO2 in subsurface geologic formations. Geomechanical failure of caprock is one of the main reasons of CO2 leakage from the storage formations. Through comprehensive assessment on the petrophysical and geomechanical heterogeneities of caprock, it is possible to predict the risk of unexpected caprock failure. To describe the fracture reactivation, the modified Barton–Bandis model is applied. In order to generate hydro-geomechanically heterogeneous fields, the negative correlation between porosity and Young’s modulus/Poisson’s ratio is applied. In comparison with the homogeneous model, effects of heterogeneity are examined in terms of vertical deformation and the amount of leaked CO2. To compare the effects of heterogeneity, heterogeneous models for both geomechanical and petrophysical properties in coupled simulation are designed. After 10-year injection with petrophysically heterogeneous and geomechanically homogeneous caprock, CO2 leakage is larger than that of the homogeneous model. In contrast, heterogeneity of geomechanical properties is shown to mitigate additional escape of CO2. Vertical displacement of every heterogeneous model is larger than homogeneous model. The model with compressive tectonic stress shows much more stable trapping with heterogeneous caprock, but there is possibility of rapid leakage after homogeneous caprock failure.
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Azad, A., and R. J. J. Chalaturnyk. "The Role of Geomechanical Observation in Continuous Updating of Thermal-Recovery Simulations With the Ensemble Kalman Filter." SPE Journal 18, no. 06 (May 29, 2013): 1043–56. http://dx.doi.org/10.2118/146898-pa.
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Summary In-situ thermal methods such as steam-assisted gravity drainage (SAGD) and cyclic steam stimulation (CSS) are widely used in oil-sand reservoirs. The physics of such thermal processes is generally well-understood, and it has been shown that rock properties are highly influenced by the geomechanical behavior of the reservoir during these recovery processes. Geomechanics improves the process dynamically, and its response can depict the progress of production within a reservoir. However, the potential of geomechanical monitoring is not usually practiced. With increased implementation of highly instrumented wells and communication technologies providing real-time monitoring data from different sources, combining available data into reservoir geomechanical simulations can improve updating numerical models and the prediction process. This research explores effective uses of geomechanical observation data for history matching and types of geomechanical observation sources adequate for thermal recovery. The ensemble Kalman filter (EnKF), combined with an iterative geomechanical coupled simulator, has been chosen as the data-assimilation algorithm to update the model continuously on the basis of geomechanical observations and production data. The results show that considering geomechanical modeling and observation improves history matching when geomechanical behavior plays a role in the process.
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Sharifi, Javad, Naser Hafezi Moghaddas, Gholam Reza Lashkaripour, Abdolrahim Javaherian, and Marzieh Mirzakhanian. "Application of extended elastic impedance in seismic geomechanics." GEOPHYSICS 84, no. 3 (May 1, 2019): R429—R446. http://dx.doi.org/10.1190/geo2018-0242.1.
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We have evaluated an innovative application of extended elastic impedance (EEI) to integrate seismic and geomechanics for geomechanical interpretation of hydrocarbon reservoirs. EEI analysis is used to extract geomechanical parameters. To verify and assess the capabilities of EEI analysis for extracting geomechanical parameters, we selected a jointed, oil-bearing, shale carbonate reservoir in the southwest of Iran, and we used petrophysical data and core analysis to estimate static and dynamic moduli of the reservoir rock. We calculated the corresponding EEI curve to different intercept-gradient coordinate rotation angles (the chi angle, [Formula: see text]), and we selected the angles of the maximum correlation for the corresponding geomechanical parameters. Then, combining the intercept and gradient, we generated 3D reflectivity patterns of EEI at different angles. To obtain a cube of geomechanical parameters, we performed model-based inversion on the EEI reflectivity pattern. A comparison between the modeling results and well data indicated that the geomechanical parameters estimated by our method were well-correlated to the observed data. Accordingly, we extracted the geomechanical and rock-physical parameters from the EEI cube. We further found that EEI analysis was capable of giving a 3D mechanical earth model of the reservoir with the appropriate accuracy. Finally, we verified the proposed methodology on a blind well and compared the results with those of the simultaneous inversion, indicating comparable levels of accuracy. Therefore, application of this method in seismic geomechanics can bring about significant progress in the future.
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ZHANG, SHIKE, YUAN YUAN, JIANQING XIAO, and SHUNDE YIN. "APPLICATION OF COMPUTATIONAL INTELLIGENCE METHOD IN PETROLEUM GEOMECHANICS CHARACTERIZATION." International Journal of Computational Intelligence and Applications 13, no. 04 (December 2014): 1450021. http://dx.doi.org/10.1142/s1469026814500217.
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Petroleum geomechanics characterization refers to the process of quantitatively assigning geomechanical parameters using all available field data. In this paper, an attempt is made to develop a computational intelligence method that integrates genetic algorithm (GA) and artificial neural network (ANN). Through this method, these geomechanical parameters such as horizontal in situ stresses, fracture aperture and joint spacing are determined based on the borehole displacements during drilling well. In the hybrid ANN–GA model, GA can automatically identify geomechanical parameters as neural inputs from monitored borehole displacements, and the ANN is trained to learn the complex relationship between geomechanical parameters and target borehole displacements. Data from numerical experiments on petroleum wells are used in verification of the proposed computational intelligence method for geomechanics characterization. The study of numerical experiment illustrates that the proposed computational intelligence method has the ability to generate reliable results.
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Younessi, Ahmadreza. "Where, when and how a field-scale 4D geomechanical model should be built." APPEA Journal 57, no. 2 (2017): 814. http://dx.doi.org/10.1071/aj16211.
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Analytical approaches have been successfully used for decades to analyse different geomechanical related problems in the oil and gas industry. These approaches are still applicable for most problems. However, they may not be suitable for complex environments that the industry is increasingly facing nowadays. The challenges to develop complex fields require the industry to have a better understanding and prediction of the behaviour of reservoir rocks and their overburden formations during field production. This can be partially achieved by conducting a more comprehensive analysis by means of numerical methods in a wider scale of space and time. We refer to this as 4D geomechanical modelling. The concept of 4D geomechanical modelling is relatively new in the industry, and there is limited knowledge regarding the applications and advantages of this type of modelling within disciplines other than geomechanics. It is essential to understand in which type of reservoirs and at what stage of development this type of modelling should be considered. Here in this manuscript, after discussing these considerations, the techniques and procedures to build and interpret a 4D geomechanical model are discussed.
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Ahmed, Barzan I., and Mohammed S. Al-Jawad. "Geomechanical modelling and two-way coupling simulation for carbonate gas reservoir." Journal of Petroleum Exploration and Production Technology 10, no. 8 (August 10, 2020): 3619–48. http://dx.doi.org/10.1007/s13202-020-00965-7.
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Abstract Geomechanical modelling and simulation are introduced to accurately determine the combined effects of hydrocarbon production and changes in rock properties due to geomechanical effects. The reservoir geomechanical model is concerned with stress-related issues and rock failure in compression, shear, and tension induced by reservoir pore pressure changes due to reservoir depletion. In this paper, a rock mechanical model is constructed in geomechanical mode, and reservoir geomechanics simulations are run for a carbonate gas reservoir. The study begins with assessment of the data, construction of 1D rock mechanical models along the well trajectory, the generation of a 3D mechanical earth model, and running a 4D geomechanical simulation using a two-way coupling simulation method, followed by results analysis. A dual porosity/permeability model is coupled with a 3D geomechanical model, and iterative two-way coupling simulation is performed to understand the changes in effective stress dynamics with the decrease in reservoir pressure due to production, and therefore to identify the changes in dual-continuum media conductivity to fluid flow and field ultimate recovery. The results of analysis show an observed effect on reservoir flow behaviour of a 4% decrease in gas ultimate recovery and considerable changes in matrix contribution and fracture properties, with the geomechanical effects on the matrix visibly decreasing the gas production potential, and the effect on the natural fracture contribution is limited on gas inflow. Generally, this could be due to slip flow of gas at the media walls of micro-extension fractures, and the flow contribution and fracture conductivity is quite sufficient for the volume that the matrixes feed the fractures. Also, the geomechanical simulation results show the stability of existing faults, emphasizing that the loading on the fault is too low to induce fault slip to create fracturing, and enhanced permeability provides efficient conduit for reservoir fluid flow in reservoirs characterized by natural fractures.
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Wang, Wenli, Julia Diessl, and Michael S. Bruno. "Surface deformation study for a geothermal operation field." Advances in Geosciences 45 (September 4, 2018): 243–49. http://dx.doi.org/10.5194/adgeo-45-243-2018.
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Abstract. GeoMechanics Technologies has investigated the surface deformation that occurred at a geothermal field operation located in New Zealand. The thermal area associated with this field has extensive surface infrastructures that are in close proximity to a lake. Geothermal operations initially began in 1997 while surface subsidence has been observed since early 2004. We were contracted by the client to review and analyze the impact of future development plans on ground level changes in hopes to mitigate further compaction and subsidence in the area. There is significant concern that continued surface subsidence may cause the lake to flood the surrounding area. An integrated 3-D geological model, geomechanical model, and fluid and heat flow model were developed for this study. To ensure accuracy, a history match and calibration was performed on the geomechanical model using historical subsidence survey data and on the fluid and heat flow simulation using historical injection and production data. The calibrated geomechanical model was then applied to simulate future scenarios to predict surface subsidence and provide a guideline to optimize field development plans.
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Hosseini, Behrooz Koohmareh, and Rick Chalaturnyk. "A Domain Splitting-Based Analytical Approach for Assessing Hydro-Thermo-Geomechanical Responses of Heavy-Oil Reservoirs." SPE Journal 22, no. 01 (July 28, 2016): 300–315. http://dx.doi.org/10.2118/170193-pa.
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Summary For stress-sensitive heavy-oil reservoirs, geomechanical responses of the reservoir are taken into account because they play an important role in the accurate simulation of all thermal recovery techniques, such as steam-assisted gravity drainage (SAGD) or steamflood. However, full-field numerical simulations of multiphysics processes by any coupling strategies are technically impossible with current computer central processing units (CPUs). Under these conditions, analytical methods can be used as approximate techniques instead of numerical simulators because they are much faster and yet are useful tools for preliminary forecasting and sensitivity studies. In analytical models, inclusion of all flow-variable impacts into geomechanics frameworks make the equations complex and almost impossible to solve. This paper provides a flow-based domain decomposition work flow for performing different analytical coupling schemes in different reservoir compartments. Because the intensity and complexity of reservoir geomechanics vary over reservoir domain, one can divide the reservoir to some subdomains and assess different geomechanical responses separately in each subdomain. The presented analytical proxy suggests decomposition of the entire domain into two parts of “heated zone” and “wetted zone,” for rapid assessment of geomechanics. The heat-flow equation was combined with mass and momentum convective-transport equations to obtain an exact approach that correlates the saturation front of injected hot water to temperature front. The frontal velocities are dynamic interfaces for compartmentalization of the domain. In the heated zone, the total induced stresses were considered because both temperature and pressure increase, and in the wetted (saturated) zone beyond the temperature front, at each instance, the total stress induced is only a function of pressure increase, and, accordingly, stress and strain induced are caused by isotropic unloading. This technique provides a rapid estimate of geomechanical responses (stress and strain profile) in each part of the reservoir (near field and far field). A numerical model was built and implemented in CMG-STARS for a steamflood case to show the robustness and applicability range of the model. The results were analyzed for a synthetic-case single-domain model, and the model sensitivity on some reservoir parameters was checked, while geomechanical responses were not neglected anywhere (near field and far field) in the reservoir. The results of the numerical model were in close agreement with the result of the proposed analytical proxy.
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Huang, Jian, Reza Safari, Uno Mutlu, Kevin Burns, Ingo Geldmacher, Mark McClure, and Stuart Jackson. "Natural-hydraulic fracture interaction: Microseismic observations and geomechanical predictions." Interpretation 3, no. 3 (August 1, 2015): SU17—SU31. http://dx.doi.org/10.1190/int-2014-0233.1.
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Natural fractures can reactivate during hydraulic stimulation and interact with hydraulic fractures producing a complex and highly productive natural-hydraulic fracture network. This phenomenon and the quality of the resulting conductive reservoir area are primarily functions of the natural fracture network characteristics (e.g., spacing, height, length, number of fracture sets, orientation, and frictional properties); in situ stress state (e.g., stress anisotropy and magnitude); stimulation design parameters (e.g., pumping schedule, the type/volume of fluid[s], and proppant); well architecture (number and spacing of stages, perforation length, well orientation); and the physics of the natural-hydraulic fracture interaction (e.g., crossover, arrest, reactivation). Geomechanical models can quantify the impact of key parameters that control the extent and complexity of the conductive reservoir area, with implications to stimulation design and well optimization in the field. We have developed a series of geomechanical simulations to predict natural-hydraulic fracture interaction and the resulting fracture network in complex settings. A geomechanics-based sensitivity analysis was performed that integrated key reservoir-geomechanical parameters to forward model complex fracture network generation, synthetic microseismic (MS) response, and associated conductivity paths as they evolve during stimulation operations. The simulations tested two different natural-hydraulic fracture interaction scenarios and could generate synthetic MS events. The sensitivity analysis revealed that geomechanical models that involve complex fracture networks can be calibrated against MS data and can help to predict the reservoir response to stimulation and optimize the conductive reservoir area. We analyzed a field data set (obtained from two hydraulically fractured wells in the Barnett Formation, Tarrant County, Texas) and established a coupling between the geomechanics and MS within the framework of a 3D geologic model. This coupling provides a mechanics-based approach to (1) verify MS trends and anomalies in the field, (2) optimize conductive reservoir area for reservoir simulations, and (3) improve stimulation design on the current well in near-real-time and well design/stimulation for future wells.
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Schutjens, P. M. T. M. M. T. M., J. R. R. Snippe, H. Mahani, J. Turner, J. Ita, and A. P. P. Mossop. "Production-Induced Stress Change in and Above a Reservoir Pierced by Two Salt Domes: A Geomechanical Model and Its Applications." SPE Journal 17, no. 01 (October 25, 2011): 80–97. http://dx.doi.org/10.2118/131590-pa.
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Summary Production decreases the pore-fluid pressure and increases the effective stress acting on the load-bearing-grain framework that makes up the reservoir. As a result, the reservoir deforms and compacts, and because it is connected to the rocks around it, there will be deformations and displacements in these rocks also. Well known geomechanical effects of production include surface subsidence, wells damaged by shear, and time shifts in 4D seismic. Less well known is how the changes in the stress field itself should be taken into account in operations—e.g., to design infill wells and to plan production stimulation by hydraulic fracturing or waterflooding of the reservoir. We present a geomechanical model for the initial stress field and production-induced stress changes in and around a steeply dipping hydrocarbon reservoir penetrated by two large salt domes. The model integrates 3D seismic and geological understanding, geomechanical data from wells and analogues, and depletion patterns from fluid-flow (dynamic) simulation. Our model results confirm published models of principal-stress orientation in rocks pierced by salt domes. The depleted-model results show stress changes up to several MPa in magnitude compared with the preproduction stress state, but only limited changes in the stress orientations. The model highlights the influence of structural dip and time-dependent salt/sediment interaction on stress changes. We then describe the application of the model in wellbore stress analysis for infill wells and in a water-injection scheme that has, we believe, been severely impacted by injection-induced fractures propagating in the reservoir from the injector wells toward the producer wells. We explain how the latter application uses a 3D flow-simulation model coupled to a dynamic fracture-propagation model. The geomechanical model provides key input: stress magnitude and stress orientation. Results are validated against a more conventional analysis of real-time pressure data. In both applications, the integration of geomechanics in 3D static and dynamic models improved insight into the rock response to drilling and waterflooding, thus helping to optimize production.
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Bondur, V. G., M. B. Gokhberg, I. A. Garagash, and D. A. Alekseev. "Three-Dimensional Geomechanical Model of Kamchatka." Izvestiya, Physics of the Solid Earth 57, no. 3 (May 2021): 309–18. http://dx.doi.org/10.1134/s1069351321030046.
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Mohammed, Rehan Ali, Seyedalireza Khatibi, Mehdi Ostadhassan, Azadeh Aghajanpour, and Alexeyev Alan. "Advanced Geomechanical Earth Model for Predicting Wellbore Stability and Fracking Potential." International Journal of Chemical Engineering and Applications 9, no. 2 (April 2018): 38–45. http://dx.doi.org/10.18178/ijcea.2018.9.2.696.
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Li, Xin, Xiang Li, Dongxiao Zhang, and Rongze Yu. "A Dual-Grid, Implicit, and Sequentially Coupled Geomechanics-and-Composition Model for Fractured Reservoir Simulation." SPE Journal 25, no. 04 (June 10, 2020): 2098–118. http://dx.doi.org/10.2118/201210-pa.
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Summary In the development of fractured reservoirs, geomechanics is crucial because of the stress sensitivity of fractures. However, the complexities of both fracture geometry and fracture mechanics make it challenging to consider geomechanical effects thoroughly and efficiently in reservoir simulations. In this work, we present a coupled geomechanics and multiphase-multicomponent flow model for fractured reservoir simulations. It models the solid deformation using a poroelastic equation, and the solid deformation effects are incorporated into the flow model rigorously. The noticeable features of the proposed model are it uses a pseudocontinuum equivalence method to model the mechanical characteristics of fractures; the coupled geomechanics and flow equations are split and sequentially solved using the fixed-stress splitting strategy, which retains implicitness and exhibits good stability; and it simulates geomechanics and compositional flow, respectively, using a dual-grid system (i.e., the geomechanics grid and the reservoir-flow grid). Because of the separation of the geomechanics part and the flow part, the model is not difficult to implement based on an existing reservoir simulator. We validated the accuracy and stability of this model through several benchmark cases and highlighted the practicability with two large-scale cases. The case studies demonstrate that this model is capable of considering the key effects of geomechanics in fractured-reservoir simulation, including matrix compaction, fracture normal deformation, and shear dilation, as well as hydrocarbon phase behavior. The flexibility, efficiency, and comprehensiveness of this model enable a more realistic geocoupled reservoir simulation.
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Shevtsov, Aleksandr, and Veniamin Khyamyalyaynen. "Geomechanical Estimation of the Influence of Horizontal Coalbed Methane Well Design on Coal Seam Permeability." E3S Web of Conferences 105 (2019): 01014. http://dx.doi.org/10.1051/e3sconf/201910501014.
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The paper presents a method of choosing the design of horizontal coalbed methane well by estimation of a coal seam permeability on the results of one-dimensional and two-dimensional geomechanical modeling. The differences in the preparation of one-dimensional geomechanical models of coalbed methane fields from models for conventional oil and gas fields are noted. The results of preparation of one-dimensional geomechanical model based on data from one of the vertical exploration coalded methane wells and two-dimensional geomechanical modeling of coal seam for three common designs are presented. The obtained results allow us to conclude that geomechanical modeling is a suitable tool for estimation of coal seam permeability changes and choosing the most effective well design for the considered mining and geological conditions. In particular, in the coal seam under study, a multilateral well can cause the greatest increasing of permeability.
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Gurbanov, I. I., and A. A. Khakimov. "FEASIBILITY STUDY OF 3D GEOMECHANICAL MODEL CONSTRUCTION FOR SAND PRODUCTION CONTROL." Oil and Gas Studies, no. 2 (May 1, 2016): 44–49. http://dx.doi.org/10.31660/0445-0108-2016-2-44-49.
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In this article the expediency of using the coupled hydrodynamic and geomechanical model for prediction of sand production probability is considered. Additionally to the review of scientific papers a comparison is made of results obtained by several synthetic models in the course of the experiment. Based on the study results there was prepared a list of the fields characteristics the presence of which should indicate the necessity of using the coupled hydrodynamic geomechanical model for calculation of conditions that might lead to sand production.
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Kamenev, P. A., A. E. Zabolotin, V. A. Degtyarev, and O. A. Zherdeva. "Geomechanical model of South Sakhalin active fault." Geosystems of Transition Zones 3, no. 3 (2019): 287–95. http://dx.doi.org/10.30730/2541-8912.2019.3.3.287-295.
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Pham, Tung Son, and Lan Cao Mai. "Geomechanical modeling - workflow and Applications." Science and Technology Development Journal 19, no. 1 (March 31, 2016): 5–15. http://dx.doi.org/10.32508/stdj.v19i1.497.
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This work aimed to present a detailed workflow for building a geomechanical model. For a case study, the workflow is then applied to a horizontal well X. The first step in building a geomechanical model is gathering data regarding well information (tubing, casing, deviation…), geological information (type of fault, permeability, reservoir radius, skin…), logs data (density, resistivity, sonic, caliper…), in-situ test data (leak-off test, formation test,…) and core data (tensile strength test, fracture toughness test, tri-axial test…). The second step is to build the geomechanical model using data analysis so that information about state of stress (vertical and principal horizontal stresses, pore pressure, concentration stress around wellbore) and rock mechanical properties (unconfined compressive strength, tensile strength, fracture toughness, Young modulus, Poisson ratio) can be determined. Moreover, the differences in data analysis for vertical and horizontal wells were also mentioned in this work. Furthermore, it is evident that the more data we get, the more accurately a geomechanical model can be built. However, in reality, not all necessary data can be obtained, so this work also explained how to draw the most information from available data so that we can minimize the number of assumptions and uncertainties. An accurate geomechanical model is very essential for others works such as well bore stability or performance prediction of a well stimulation technique. The case study of this work presented the geomechanical modeling for the well X. The paper then presented the application of geomechanical modeling for the Evaluation of High Energy Gas Fracturing performance as well as for Sand Control analysis.
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Shoemaker, Michael, Santhosh Narasimhan, Shane Quimby, and James Hawkins. "Calculating far-field anisotropic stress from 3D seismic in the Permian Basin." Leading Edge 38, no. 2 (February 2019): 96–105. http://dx.doi.org/10.1190/tle38020096.1.
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Minimum horizontal stress (Sh) is the controlling parameter when hydraulic fracture stimulating tight oil formations but is next to impossible to measure quantitatively, especially in the far field and away from the wellbore. In-situ stress differences between bedding planes control fracture containment, which defines the complexity of fracture propagation and fracture geometry including orientation, height growth, width, and length. Geomechanical rock properties define elastic behavior, influencing how the subsurface will deform under induced stress. These properties include dynamic and static Young's modulus, Poisson's ratio, and Biot's coefficient. When combined with pore pressure and overburden stress, the elastic rock properties describe the mechanical earth model (MEM), which characterizes the geomechanical behavior of the subsurface. The MEM also defines key inputs for calculating Sh using the Ben Eaton stress equation, which has been commonly used by geoscientists for decades. However, calculated Sh from this simple model historically produces uncertain results when compared to field-measured stress due to an assumed homogeneous and isotropic subsurface. This is particularly contrary to tight oil formations that represent shale (or mudrock) reservoirs that are highly laminated and therefore anisotropic. Optimal parameterization of fracture geometry models for well spacing and engineered treatment design requires an anisotropic far-field in-situ stress measurement that accurately captures vertical and lateral variability of geomechanical properties in 3D space. A method is proposed herein that achieves this by using a modified version of the anisotropic Ben Eaton stress model. The method calculates minimum Sh by substitution of inverted 3D seismic volumes directly into the stress equation, replacing the bound Poisson's ratio term with an equivalent anisotropic corrected closure stress scalar (CSS) term. The CSS seismic volume is corrected for anisotropy using static triaxial core and is calibrated to multidomain data types including petrophysics, rock physics, geomechanics, and completion and reservoir engineering field measurements.
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Yang, Xiangtong, Yuanwei Pan, Wentong Fan, Yongjie Huang, Yang Zhang, Lizhi Wang, Lipeng Wang, et al. "Case Study: 4D Coupled Reservoir/Geomechanics Simulation of a High-Pressure/High-Temperature Naturally Fractured Reservoir." SPE Journal 23, no. 05 (June 21, 2018): 1518–38. http://dx.doi.org/10.2118/187606-pa.
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Summary The Keshen Reservoir is a naturally fractured, deep, tight sandstone gas reservoir under high tectonic stress. Because the reservoir matrix is very tight, the natural-fracture system is the main pathway for gas production. Meanwhile, stimulation is still required for most production wells to provide production rates that sufficiently compensate for the high cost of drilling and completing wells to access this deep reservoir. Large depletion (and related stress change) was expected during the course of the production of the field. The dynamic response of the reservoir and related risks, such as reduction of fracture conductivity, fault reactivation, and casing failure, would compromise the long-term productivity of the reservoir. To quantify the dynamic response of the reservoir and related risks, a 4D reservoir/geomechanics simulation was conducted for Keshen Reservoir by following an integrated work flow. The work started from systematic laboratory fracture-conductivity tests performed with fractured cores to measure conductivity vs. confining stress for both natural fractures and hydraulic fractures (with proppant placed in the fractures of the core samples). Natural-fracture modeling was conducted to generate a discrete-fracture network (DFN) to delineate spatial distribution of the natural-fracture system. In addition, hydraulic-fracture modeling was conducted to delineate the geometry of the hydraulic-fracture system for the stimulated wells. Then, a 3D geomechanical model was constructed by integrating geological, petrophysical, and geomechanical data, and both the DFN and hydraulic-fracture system were incorporated into the 3D geomechanical model. A 4D reservoir/geomechanics simulation was conducted through coupling with a reservoir simulator to predict variations of stress and strain of rock matrix as well as natural fractures and hydraulic fractures during field production. At each study-well location, a near-wellbore model was extracted from the full-field model, and casing and cement were installed to evaluate well integrity during production. The 4D reservoir/geomechanics simulation revealed that there would be a large reduction of conductivity for both natural fractures and hydraulic fractures, and some fractures with certain dip/dip azimuth will be reactivated during the course of field production. The induced-stress change will also compromise well integrity for those poorly cemented wellbores. The field-development plan must consider all these risks to ensure sustainable long-term production. The paper presents a 4D coupled geomechanics/reservoir-simulation study applied to a high-pressure/high-temperature (HP/HT) naturally fractured reservoir, which has rarely been published previously. The study adapted several new techniques to quantify the mechanical response of both natural fractures and hydraulic fractures, such as using laboratory tests to measure stress sensitivity of natural fractures, integrating DFN and hydraulic-fracture systems into 4D geomechanics simulation, and evaluating well integrity on both the reservoir scale and the near-wellbore scale.
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Kim, Jihoon, and George J. Moridis. "Gas Flow Tightly Coupled to Elastoplastic Geomechanics for Tight- and Shale-Gas Reservoirs: Material Failure and Enhanced Permeability." SPE Journal 19, no. 06 (June 18, 2014): 1110–25. http://dx.doi.org/10.2118/155640-pa.
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Summary We investigate coupled flow and geomechanics in gas production from extremely low-permeability reservoirs such as tight- and shale-gas reservoirs, using dynamic porosity and permeability during numerical simulation. In particular, we take the intrinsic permeability as a step function of the status of material failure, and the permeability is updated every timestep. We consider gas reservoirs with the vertical and horizontal primary fractures, using the single- and dynamic double-porosity (dual-continuum) models. We modify the multiple-porosity constitutive relations for modeling the double porous continua for flow and geomechanics. The numerical results indicate that the production of gas causes redistribution of the effective-stress fields, increasing the effective shear stress and resulting in plasticity. Shear failure occurs not only near the fracture tips but also away from the primary fractures, which indicates the generation of secondary fractures. These secondary fractures increase the permeability significantly, and change the flow pattern, which, in turn, causes a change in the distribution of geomechanical variables. From various numerical tests, we find that shear failure is enhanced by a large pressure drop at the production well, a high Biot's coefficient, and low frictional and dilation angles. Smaller spacing between the horizontal wells also contributes to faster secondary fracturing. When the dynamic double-porosity model is used, we observe a faster evolution of the enhanced-permeability areas than that obtained from the single-porosity model, mainly because of a higher permeability of the fractures in the double-porosity model. These complicated physics for stress-sensitive reservoirs cannot properly be captured by the uncoupled or flow-only simulation, and, thus, tightly coupled flow and geomechanical models are highly recommended to describe accurately the reservoir behavior during gas production in tight- and shale-gas reservoirs and to design production scenarios smartly.
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Djukem, Wamba Danny Love, Anika Braun, Armand Sylvain Ludovic Wouatong, Christian Guedjeo, Katrin Dohmen, Pierre Wotchoko, Tomas Manuel Fernandez-Steeger, and Hans-Balder Havenith. "Effect of Soil Geomechanical Properties and Geo-Environmental Factors on Landslide Predisposition at Mount Oku, Cameroon." International Journal of Environmental Research and Public Health 17, no. 18 (September 17, 2020): 6795. http://dx.doi.org/10.3390/ijerph17186795.
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In this work, we explored a novel approach to integrate both geo-environmental and soil geomechanical parameters in a landslide susceptibility model. A total of 179 shallow to deep landslides were identified using Google Earth images and field observations. Moreover, soil geomechanical properties of 11 representative soil samples were analyzed. The relationship between soil properties was evaluated using the Pearson correlation coefficient and geotechnical diagrams. Membership values were assigned to each soil property class, using the fuzzy membership method. The information value method allowed computing the weight value of geo-environmental factor classes. From the soil geomechanical membership values and the geo-environmental factor weights, three landslide predisposition models were produced, two separate models and one combined model. The results of the soil testing allowed classifying the soils in the study area as highly plastic clays, with high water content, swelling, and shrinkage potential. Some geo-environmental factor classes revealed their landslide prediction ability by displaying high weight values. While the model with only soil properties tended to underrate unstable and stable areas, the model combining soil properties and geo-environmental factors allowed a more precise identification of stability conditions. The geo-environmental factors model and the model combining geo-environmental factors and soil properties displayed predictive powers of 80 and 93%, respectively. It can be concluded that the spatial analysis of soil geomechanical properties can play a major role in the detection of landslide prone areas, which is of great interest for site selection and planning with respect to sustainable development at Mount Oku.
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Gai, Xuerui, and Marcelo Sánchez. "A geomechanical model for gas hydrate-bearing sediments." Environmental Geotechnics 4, no. 2 (April 2017): 143–56. http://dx.doi.org/10.1680/jenge.15.00050.
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Fanchi, J. R. "Estimating Geomechanical Properties Using an Integrated Flow Model." SPE Reservoir Evaluation & Engineering 6, no. 02 (April 1, 2003): 108–16. http://dx.doi.org/10.2118/83730-pa.
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Shahri, Mojtaba P., Trevor T. Oar, Reza Safari, Moji Karimi, and Uno Mutlu. "Advanced Semianalytical Geomechanical Model for Wellbore-Strengthening Applications." SPE Journal 20, no. 06 (December 18, 2015): 1276–86. http://dx.doi.org/10.2118/167976-pa.
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Summary Drilling depleted reservoirs often encounters a host of problems leading to increases in cost and nonproductive time. One of these problems faced by drillers is lost circulation of drilling fluids, which can lead to greater issues such as differential sticking and well-control events. Field applications show that wellbore strengthening effectively helps reduce mud-loss volume by increasing the safe mud-weight window. Wellbore-strengthening applications are usually designed on the basis of induced-fracture characteristics (i.e., fracture length, fracture width, and stress-intensity factor). In general, these fracture characteristics depend on several parameters, including in-situ stress magnitude, in-situ stress anisotropy, mechanical properties, rock texture, wellbore geometry, mud weight, wellbore trajectory, pore pressure, natural fractures, and formation anisotropy. Analytical models available in the literature oversimplify the fracture-initiation and fracture-propagation process with assumptions such as isotropic stress field, no near-wellbore stress-perturbation effects, vertical or horizontal wells only (no deviation/inclination), constant fracture length, and constant pressure within the fracture. For more-accurate predictions, different numerical methods, such as finite element and boundary element, have been used to determine fracture-width distribution. However, these calculations can be computationally costly or difficult to implement in near-real time. The aim of this study is to provide a fast-running, semianalytical work flow to accurately predict fracture-width distribution and fracture-reinitiation pressure (FRIP). The algorithm and work flow can account for near-wellbore-stress perturbations, far-field-stress anisotropy, and wellbore inclination/deviation. The semianalytical algorithm is modeled after singular integral formulation of stress field and solved by use of Gauss-Chebyshev polynomials. The proposed model is computationally efficient and accurate. The model also provides a comprehensive perspective on formation-strengthening scenarios; a tool for improved lost-circulation-materials design; and an explanation of how they are applicable during drilling operation (in particular, through depleted zones). Sensitivity analysis included in this paper quantifies the effect of different rock properties, in-situ-stress field/anisotropy, and wellbore geometry/deviation on the fracture-width distribution and FRIP. In addition, the case study presented in this paper demonstrates the applicability of the proposed work flow in the field.
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Prevost, Jean H. "Two-way coupling in reservoir-geomechanical models: vertex-centered Galerkin geomechanical model cell-centered and vertex-centered finite volume reservoir models." International Journal for Numerical Methods in Engineering 98, no. 8 (March 19, 2014): 612–24. http://dx.doi.org/10.1002/nme.4657.
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Irani, Mazda. "Predicting Geomechanical Dynamics of the Steam-Assisted-Gravity-Drainage Process. Part I: Mohr-Coulomb (MC) Dilative Model." SPE Journal 23, no. 04 (February 21, 2018): 1223–47. http://dx.doi.org/10.2118/189976-pa.
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Summary In the steam-assisted-gravity-drainage (SAGD) recovery process, the injection of high-pressure/high-temperature steam causes significant stress changes at the edge of the heated zone or steam chamber. These stress changes include shear dilation, which can both enhance the absolute permeability and result in horizontal and vertical formation displacements. The importance of considering geomechanical effects in thermal-recovery processes has been extensively discussed in the literature, but the prediction and surveillance of the resulting effects, such as the impact on production enhancement and reservoir displacement, have in many cases been neglected. Furthermore, issues related to these geomechanical effects on thermal production have been the subject of considerable debate in the industry with no conclusive, meaningful assessments of the effect on reservoir deliverability and production, or of the associated risks that such geomechanical effects have on wellbore and caprock integrity. This study will focus on identification of the main findings from an extensive monitoring program conducted on the original SAGD pilot project conducted at the Underground Test Facility (UTF) in the late 1980s and a seismic program conducted during the last several years by an SAGD operator at a commercial thermal-recovery project. The measured displacements and identified dilation shear zones in these applications were compared with a Mohr-Coulomb (MC) dilative model. This paper illustrates some of the pros and cons of using such analytical models through comparison of the results based on field evidence of the dilation and shearing effects, and how these mechanisms affect both reservoir productivity (revenue) and wellbore and caprock integrity. Although the discussion on the geomechanical effects in thermal-recovery processes will no doubt continue, this study will provide field-supported results to illustrate both beneficial and potentially challenging impacts that these geomechanical effects can have in a thermal-recovery project.
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Li, Zhiqiang, Zhilin Qi, Wende Yan, Zuping Xiang, Xiang Ao, Xiaoliang Huang, and Fei Mo. "Prediction of Production Performance of Refractured Shale Gas Well considering Coupled Multiscale Gas Flow and Geomechanics." Geofluids 2020 (February 6, 2020): 1–21. http://dx.doi.org/10.1155/2020/9160346.
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Production simulation is an important method to evaluate the stimulation effect of refracturing. Therefore, a production simulation model based on coupled fluid flow and geomechanics in triple continuum including kerogen, an inorganic matrix, and a fracture network is proposed considering the multiscale flow characteristics of shale gas, the induced stress of fracture opening, and the pore elastic effect. The complex transport mechanisms due to multiple physics, including gas adsorption/desorption, slip flow, Knudsen diffusion, surface diffusion, stress sensitivity, and adsorption layer are fully considered in this model. The apparent permeability is used to describe the multiple physics occurring in the matrix. The model is validated using actual production data of a horizontal shale gas well and applied to predict the production and production increase percentage (PIP) after refracturing. A sensitivity analysis is performed to study the effects of the refracturing pattern, fracture conductivity, width of stimulated reservoir volume (SRV), SRV length of new and initial fractures, and refracturing time on production and the PIP. In addition, the effects of multiple physics on the matrix permeability and production, and the geomechanical effects of matrix and fracture on production are also studied. The research shows that the refracturing design parameters have an important influence on the PIP. The geomechanical effect is an important cause of production loss, while slippage and diffusion effects in matrix can offset the production loss.
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Yang, Baoquan, Lin Zhang, Enlong Liu, Jianhua Dong, Honghu Zhu, and Yuan Chen. "Deformation Monitoring of Geomechanical Model Test and Its Application in Overall Stability Analysis of a High Arch Dam." Journal of Sensors 2015 (2015): 1–12. http://dx.doi.org/10.1155/2015/470905.
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Geomechanical model testing is an important method for studying the overall stability of high arch dams. The main task of a geomechanical model test is deformation monitoring. Currently, many types of deformation instruments are used for deformation monitoring of dam models, which provide valuable information on the deformation characteristics of the prototype dams. However, further investigation is required for assessing the overall stability of high arch dams through analyzing deformation monitoring data. First, a relationship for assessing the stability of dams is established based on the comprehensive model test method. Second, a stability evaluation system is presented based on the deformation monitoring data, together with the relationships between the deformation and overloading coefficient. Finally, the comprehensive model test method is applied to study the overall stability of the Jinping-I high arch dam. A three-dimensional destructive test of the geomechanical model dam is conducted under reinforced foundation conditions. The deformation characteristics and failure mechanisms of the dam abutments and foundation were investigated. The test results indicate that the stability safety factors of the dam abutments and foundation range from 5.2 to 6.0. These research results provide an important scientific insight into the design, construction, and operation stages of this project.
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Zoccarato, C., D. Baù, F. Bottazzi, M. Ferronato, G. Gambolati, S. Mantica, and P. Teatini. "Estimate of a spatially variable reservoir compressibility by assimilation of ground surface displacement data." Proceedings of the International Association of Hydrological Sciences 372 (November 12, 2015): 351–56. http://dx.doi.org/10.5194/piahs-372-351-2015.
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Abstract. Fluid extraction from producing hydrocarbon reservoirs can cause anthropogenic land subsidence. In this work, a 3-D finite-element (FE) geomechanical model is used to predict the land surface displacements above a gas field where displacement observations are available. An ensemble-based data assimilation (DA) algorithm is implemented that incorporates these observations into the response of the FE geomechanical model, thus reducing the uncertainty on the geomechanical parameters of the sedimentary basin embedding the reservoir. The calibration focuses on the uniaxial vertical compressibility cM, which is often the geomechanical parameter to which the model response is most sensitive. The partition of the reservoir into blocks delimited by faults motivates the assumption of a heterogeneous spatial distribution of cM within the reservoir. A preliminary synthetic test case is here used to evaluate the effectiveness of the DA algorithm in reducing the parameter uncertainty associated with a heterogeneous cM distribution. A significant improvement in matching the observed data is obtained with respect to the case in which a homogeneous cM is hypothesized. These preliminary results are quite encouraging and call for the application of the procedure to real gas fields.
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Li, Yueting, Matteo Frigo, Yan Zhang, Lin Zhu, Massimiliano Ferronato, Carlo Janna, Xulong Gong, Jun Yu, Pietro Teatini, and Shujun Ye. "A New Software to Model Earth Fissure Caused by Extensive Aquifer Exploitation and its Application to the Guangming Village Case, China." Proceedings of the International Association of Hydrological Sciences 382 (April 22, 2020): 511–14. http://dx.doi.org/10.5194/piahs-382-511-2020.
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Abstract. Earth fissures accompanying anthropogenic land subsidence due to excessive aquifer exploitation create significant geohazards in China. Numerical models represent a unique scientific approach to predict the generation and development of earth fissures. However, the common geomechanical simulators fail to reproduce fissure development because they cannot be effectively applied in discontinuous mechanics. An innovative modelling approach developed recently is applied to develop a software to simulate fissure development. The pressure changes are used as forcing factors in a 3D geomechanical model, which combines Finite Elements and Interface Elements to simulate the deformation of the continuous aquifer system and the generation and sliding/opening of earth fissures. The approach has been applied to simulate the earth fissures at Guangming Village in Wuxi, China with land subsidence of more than 1 m caused by the overexploitation of the second confined aquifer. The modelling results highlight that the earth fissures at Guangming Village have been caused by tension and shear stresses. Based on the developed modelling approach and the application case study, a software platform is developed to provide a fast preliminary evaluation of the risk of fissure occurrence associated to land subsidence. The software allows for the simulation of a simplified 2D conceptual geologic model of earth fissures, which can be used to investigate how the main factors controlling the geomechanical response of the aquifer system, such as pressure changes, geometry of aquifer system, geomechanical properties, and depth of bedrock/fault etc.
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Sadrnejad, S. A., Hasan Ghasemzadeh, and Ehsan Taheri. "MULTISCALE MULTIPHYSIC MIXED GEOMECHANICAL MODEL IN DEFORMABLE POROUS MEDIA." International Journal for Multiscale Computational Engineering 12, no. 6 (2014): 529–47. http://dx.doi.org/10.1615/intjmultcompeng.2014011296.
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Zoccarato, C., C. Da Lio, L. Tosi, and Pietro Teatini. "A Coupled Biomorpho‐Geomechanical Model of Tidal Marsh Evolution." Water Resources Research 55, no. 11 (November 2019): 8330–49. http://dx.doi.org/10.1029/2019wr024875.
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Denisova, E. V., and A. I. Konurin. "Geomechanical model of the pneumatic borer and soil interaction." Journal of Mining Science 49, no. 5 (September 2013): 724–30. http://dx.doi.org/10.1134/s1062739149050055.
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Gaede, Oliver, Moritz Ziegler, and Oliver Heidbach. "Building a 3D Geomechanical Model for the Fitzroy Trough." ASEG Extended Abstracts 2019, no. 1 (November 11, 2019): 1–4. http://dx.doi.org/10.1080/22020586.2019.12073133.
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Kong, Lingyun, Mehdi Ostadhassan, Siavash Zamiran, Bo Liu, Chunxiao Li, and Gennaro G. Marino. "Geomechanical Upscaling Methods: Comparison and Verification via 3D Printing." Energies 12, no. 3 (January 25, 2019): 382. http://dx.doi.org/10.3390/en12030382.
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Understanding geomechanical properties of rocks at multiple scales is critical and relevant in various disciplines including civil, mining, petroleum and geological engineering. Several upscaling frameworks were proposed to model elastic properties of common rock types from micro to macroscale, considering the heterogeneity and anisotropy in the samples. However, direct comparison of the results from different upscaling methods remains limited, which can question their accuracy in laboratory experiments. Extreme heterogeneity of natural rocks that arises from various existing components in them adds complexity to verifying the accuracy of these upscaling methods. Therefore, experimental validation of various upscaling methods is performed by creating simple component materials, which is, in this study, examining the predicted macroscale geomechanical properties of 3D printed rocks. Nanoindentation data were first captured from 3D printed gypsum powder and binder rock fragments followed by, triaxial compression tests on similar cylindrical core plugs to acquire modulus values in micro and macroscale respectively. Mori-Tanaka (MT) scheme, Self-Consistent Scheme (SCS) method and Differential Effective Medium (DEM) theory were used to estimate Young’s modulus in macroscale based on the results of nanoindentation experiments. The comparison demonstrated that M-T and SCS methods would provide us with more comparable results than DEM method. In addition, the potential applications of 3D printed rocks were also discussed regarding rock physics and the geomechanics area in petroleum engineering and geosciences.
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Fischer, K., and A. Henk. "3-D geomechanical modelling of a gas reservoir in the North German Basin: workflow for model building and calibration." Solid Earth Discussions 5, no. 1 (June 7, 2013): 767–88. http://dx.doi.org/10.5194/sed-5-767-2013.
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Abstract. The optimal use of conventional and unconventional hydrocarbon reservoirs depends, amongst others, on the local tectonic stress field. For example, wellbore stability, orientation of hydraulically induced fractures and – especially in fractured reservoirs – permeability anisotropies are controlled by the recent in situ stresses. Faults and lithological changes can lead to stress perturbations and produce local stresses that can significantly deviate from the regional stress field. Geomechanical reservoir models aim for a robust, ideally "pre-drilling" prediction of the local variations in stress magnitude and orientation. This requires a~numerical modelling approach that is capable to incorporate the specific geometry and mechanical properties of the subsurface reservoir. The workflow presented in this paper can be used to build 3-D geomechanical models based on the Finite Element Method (FEM) and ranging from field-scale models to smaller, detailed submodels of individual fault blocks. The approach is successfully applied to an intensively faulted gas reservoir in the North German Basin. The in situ stresses predicted by the geomechanical FE model were calibrated against stress data actually observed, e.g. borehole breakouts and extended leak-off tests. Such a validated model can provide insights into the stress perturbations in the inter-well space and undrilled parts of the reservoir. In addition, the tendency of the existing fault network to slip or dilate in the present-day stress regime can be addressed.
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Malinouskaya, Iryna, Christophe Preux, Nicolas Guy, and Gisèle Etienne. "Impact of geomechanical effects during SAGD process in a meander belt." Oil & Gas Sciences and Technology – Revue d’IFP Energies nouvelles 73 (2018): 17. http://dx.doi.org/10.2516/ogst/2018011.
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In the reservoir simulations, the geomechanical effects are usually taken into account to describe the porosity and the permeability variations. In this paper, we present a new method, patented by authors, which allows to model the geomechanical effects also on the well productivity index. The Steam Assisted Gravity Drainage (SAGD) method is widely used for the heavy oil production. A very high variation in pressure and temperature play a significant role on the petrophysical properties and may impact the productivity estimation. In this paper we develop a new simplified geomechanical model in order to account for the thermal and pressure effects on the porosity, permeability and the productivity index during the reservoir simulation. At the current state, these dependencies are defined using semi-analytical relationships. The model is applied to a meandering fluvial reservoir based on 3D outcrop observations. The productivity is found underestimated if the pressure and temperature effects on the petrophysical properties are ignored in the reservoir simulation. Moreover, this study shows an important impact of thermal effects on the productivity estimation. The results of this work show that it is essential to properly take into account the geomechanical effects on the petrophysical properties and also on the productivity index for a better productivity estimation.
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Van Wees, Jan-Diederik, Peter A. Fokker, Karin Van Thienen-Visser, Brecht B. T. Wassing, Sander Osinga, Bogdan Orlic, Saad A. Ghouri, Loes Buijze, and Maarten Pluymaekers. "Geomechanical models for induced seismicity in the Netherlands: inferences from simplified analytical, finite element and rupture model approaches." Netherlands Journal of Geosciences 96, no. 5 (December 2017): s183—s202. http://dx.doi.org/10.1017/njg.2017.38.
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AbstractIn the Netherlands, over 190 gas fields of varying size have been exploited, and 15% of these have shown seismicity. The prime cause for seismicity due to gas depletion is stress changes caused by pressure depletion and by differential compaction. The observed onset of induced seismicity due to gas depletion in the Netherlands occurs after a considerable pressure drop in the gas fields. Geomechanical studies show that both the delay in the onset of induced seismicity and the nonlinear increase in seismic moment observed for the induced seismicity in the Groningen field can be explained by a model of pressure depletion, if the faults causing the induced seismicity are not critically stressed at the onset of depletion. Our model shows concave patterns of log moment with time for individual faults. This suggests that the growth of future seismicity could well be more limited than would be inferred from extrapolation of the observed trend between production or compaction and seismicity. The geomechanical models predict that seismic moment increase should slow down significantly immediately after a production decrease, independently of the decay rate of the compaction model. These findings are in agreement with the observed reduced seismicity rates in the central area of the Groningen field immediately after production decrease on 17 January 2014. The geomechanical model findings therefore support scope for mitigating induced seismicity by adjusting rates of production and associated pressure change. These simplified models cannot serve as comprehensive models for predicting induced seismicity in any particular field. To this end, a more detailed field-specific study, taking into account the full complexity of reservoir geometry, depletion history and mechanical properties, is required.
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Sirdesai, N. N., R. Singh, T. N. Singh, and P. G. Ranjith. "Numerical and experimental study of strata behavior and land subsidence in an underground coal gasification project." Proceedings of the International Association of Hydrological Sciences 372 (November 12, 2015): 455–62. http://dx.doi.org/10.5194/piahs-372-455-2015.
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Abstract. Underground Coal Gasification, with enhanced knowledge of hydrogeological, geomechanical and environmental aspects, can be an alternative technique to exploit the existing unmineable reserves of coal. During the gasification process, petro-physical and geomechanical properties undergo a drastic change due to heating to elevated temperatures. These changes, caused due to the thermal anisotropy of various minerals, result in the generation of thermal stresses; thereby developing new fracture pattern. These fractures cause the overhead rock strata to cave and fill the gasification chamber thereby causing subsidence. The degree of subsidence, change in fluid transport and geomechanical properties of the rock strata, in and around the subsidence zone, can affect the groundwater flow. This study aims to predict the thermo-geomechanical response of the strata during UCG. Petro-physical and geomechanical properties are incorporated in the numerical modelling software COMSOL Multiphysics and an analytical strength model is developed to validate and further study the mechanical response and heat conduction of the host rock around the gasification chamber. Once the problems are investigated and solved, the enhanced efficiency and the economic exploitation of gasification process would help meet country's energy demand.
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Zheng, Majia, Hongming Tang, Hu Li, Jian Zheng, and Cui Jing. "Geomechanical Analysis for Deep Shale Gas Exploration Wells in the NDNR Blocks, Sichuan Basin, Southwest China." Energies 13, no. 5 (March 2, 2020): 1117. http://dx.doi.org/10.3390/en13051117.
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The abundant reserve of shale gas in Sichuan Basin has become a significant natural gas component in China. To achieve efficient development of shale gas, it is necessary to analyze the stress state, pore pressure, and reservoir mechanical properties such that an accurate geomechanical model can be established. In this paper, Six wells of Neijiang-Dazu and North Rongchang (NDNR) Block were thoroughly investigated to establish the geomechanical model for the study area. The well log analysis was performed to derive the in-situ stresses and pore pressure while the stress polygon was applied to constrain the value of the maximum horizontal principal stress. Image and caliper data, mini-frac test and laboratory rock mechanics test results were used to calibrate the geomechanical model. The model was further validated by comparing the model prediction against the actual wellbore failure observed in the field. It was found that it is associated with the strike-slip (SS) stress regime; the orientation of SHmax was inferred to be 106–130° N. The pore pressure appears to be approximately hydrostatic from the surface to 1000 m true vertical depth (TVD), but then becomes over-pressured from the Xujiahe formation. The geomechanical model can provide guidance for the subsequent drilling and completion in this area and be used to effectively avoid complex drilling events such as collapse, kick, and lost circulation (mud losses) along the entire well. Also, the in-situ stress and pore pressure database can be used to analyze wellbore stability issues as well as help design hydraulic fracturing operations.
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Alpak, Faruk O., and Jeroen C. Vink. "Coupled Numerical Simulation of Thermal-Reactive Flow and Geomechanics with Solid Mass Conversion." SPE Journal 25, no. 01 (September 23, 2019): 310–25. http://dx.doi.org/10.2118/193908-pa.
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Summary An extension of the novel fully coupled thermal-hydromechanical (THM) open-system geomechanics (OSG) model is developed for the analysis of coupled flow and oil-shale geomechanics. The model is cast within the framework of Biot's elasticity and classical thermoelasticity. A new term in the equations accounting for the effects of pyrolysis is included in the present model to capture the removal of mass from the reactive solid phase because of the kerogen-conversion process modeled through a simplified chemical-reaction model. The proposed novel formulation approach and its numerical implementation differ from traditional methods and offer a step improvement in the geomechanical modeling of thermally reactive porous media, such as oil shales. The numerical implementation of the OSG model, a first in the literature, is developed within the framework of a proprietary coupled thermal-reactive flow and geomechanics simulator, which was extensively validated in a previous publication. In this paper, we compare the thermal-reactive OSG model against experimental measurements. Numerical results from the validation test show that the model captures the fundamental physical behavior of oil-shale geomechanics realistically and correctly. Parametric analyses of the OSG model indicate that the chemical conversion term is the critical term that dictates the magnitude of compaction in the solid equation, and a further investigation illustrates the importance of the mobility term in the pore-pressure buildup. It is also noticed that the initiation and the rate of compaction of the oil-shale sample are governed by the chemical activation energy and the reaction-rate constant.
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Bonì, Roberta, Claudia Meisina, Pietro Teatini, Francesco Zucca, Claudia Zoccarato, Andrea Franceschini, Pablo Ezquerro, et al. "Understanding the dynamic behaviour for the Madrid aquifer (Spain): insights from the integration of A-DInSAR and 3-D groundwater flow and geomechanical models." Proceedings of the International Association of Hydrological Sciences 382 (April 22, 2020): 409–14. http://dx.doi.org/10.5194/piahs-382-409-2020.
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Abstract. Advanced Differential Interferometric Synthetic Aperture Radar (A-DInSAR) techniques and 3-D groundwater flow and geomechanical models are integrated to improve our knowledge about the Tertiary detritic aquifer of Madrid (TDAM). In particular, the attention is focused on the Manzanares-Jarama well field, located to the northwest of Madrid, which experienced five cycles of extensive groundwater withdrawal followed by natural recovery, to cope with the droughts occurred in summer 1995, 1999, 2002, 2006, and 2009. Piezometric records and A-DInSAR data acquired by ERS-1/2 and ENVISAT satellites during the periods 1992–2000 and 2002–2010, respectively, have been used to calibrate the groundwater flow and the geomechanical models. A time-lag of about one month between the hydraulic head changes and the displacements of the land surface has been detected by a joint wavelet analysis of A-DInSAR and piezometer head time series. Overall, the results show the effectiveness of the proposed integrated approach composed of A-DInSAR and 3-D geomechanical model to characterize the aquifer-system response during and after the groundwater withdrawal.
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Suzuki, Satomi, Colin Daly, Jef Karel Caers, and Dietmar Mueller. "History Matching of Naturally Fractured Reservoirs Using Elastic Stress Simulation and Probability Perturbation Method." SPE Journal 12, no. 01 (March 1, 2007): 118–29. http://dx.doi.org/10.2118/95498-pa.
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Summary The application of elastic stress simulation for fracture modeling provides a more realistic description of fracture distribution than conventional statistical and geostatistical techniques, allowing the integration of geomechanical data and models into reservoir characterization. The geomechanical prediction of the fracture distribution accounts for the propagation of fracture caused by stress perturbation associated with faults. However, the challenge lies in estimating the past remote stress conditions which induced structural deformation and fracturing, the limited applicability of the elasticity assumption, and the latent uncertainty in the structural geometry of faults. The integration of historical production data and well-test permeability into geomechanical fracture modeling is a practical way to reduce such uncertainty. We propose to combine geostatistical algorithms for history matching with geomechanical elastic simulation models for developing an integrated yet efficient fracture modeling tool. This paper presents an integrated approach to history matching of naturally fractured reservoirs which includes (1) fracture trend prediction through elastic stress simulation; (2) geostatistical population of fracture density based on a fracture trend model; (3) fracture permeability modeling integrating fracture density, matrix permeability and well-test permeability; and (4) numerical flow simulation and history matching. All of these implementations are incorporated into a single forward modeling process and iterated in the automatic history-matching scheme. To obtain a history match on a reservoir model, we jointly perturb the large-scale fracture trend and local-scale geostatistical fluctuations of fracture densities rather than perturbing permeability calibrated from fractures. This strategy enables us to preserve the geological/geomechanical consistency throughout the history-matching process. The geomechanically simulated fracture trend model is calibrated to both production data and the reservoir geological structure (faults and horizons) by searching for the optimum remote stress condition for elastic stress-field simulation. The latter is achieved by matching the actually observed structural deformation with the simulated one. The smaller-scale fluctuation of fracture density is simultaneously history matched through the probability perturbation method of Caers (Caers 2003; Hoffman and Caers 2005; Caers 2007). The methodology is presented on a synthetic reservoir application. Introduction The modeling of the density and pattern of fracture distributions can take different approaches depending on the origin and the type of fracture sets and on the ultimate reservoir engineering questions raised. In this paper, we focus on the modeling of shear fractures which are generated by structural deformation accompanied with fault slip. Recently, an application of the elastic stress simulation has been proposed for predicting the pattern of shear/tensile fractures or the pattern of secondary faults and shown promising results (Bourne and Willemse 2001; Maerten et al. 2002; Bourne et al. 2001). The elastic simulation numerically simulates the structural deformation of the reservoir by solving linear elasticity equations under given boundary conditions, and simultaneously calculates the corresponding stress/strain tensor fields (Bourne and Willemse 2001; Maerten et al. 2002; Bourne et al. 2001; Daly and Mueller 2004; Roxar FracPerm Reference Manual 2005). The boundary conditions consist of (1) location/geometry of fault surface, (2) stress conditions or displacement conditions on the fault surfaces, and (3) the remote loads applied to the structure at the time of structural deformation accompanied with fault slippage. First, satisfying boundary conditions and by minimizing strain energy, the linear elastic equations are solved to obtain a structural deformation field which is expressed by the displacement vector. Next, strain field is computed from the displacement gradient based on the definition of strain. Finally, under the assumption of elasticity, stress is calculated from strain by means of Hook's law.
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Pham, Son Tung. "Study of Sand Production Using Geomechanical and Hydro-Mechanical Models." Applied Mechanics and Materials 876 (February 2018): 181–86. http://dx.doi.org/10.4028/www.scientific.net/amm.876.181.
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Sand production is a complicated physical process depending on rock mechanical properties and flow of fluid in the reservoir. When it comes to sand production phenomenon, many researchers applied the Geomechanical model to predict the pressure for the onset of sand production in the reservoir. However, the mass of produced sand is difficult to determine due to the complexity of rock behavior as well as fluid behavior in porous media. In order to solve this problem, there are some Hydro – Mechanical models that can evaluate sand production rate. As these models require input parameters obtained by core analysis and use a large empirical correlation, they are still not used popularly because of the diversity of reservoirs behavior in the world. In addition, the reliability of these models is still in question because no comparison between these empirical models has been studied. The onset of sand production is estimated using the bottomhole pressure that makes the maximum effective tangential compressive stress equal or higher than the rock strength (failure criteria), which is usually known as critical bottomhole pressure (CBHP). Combining with Hydro – Mechanical model, the main objective of this work aims to develop a numerical model that can solve the complexity of the governing equations relating to sand production. The outcome of this study depicts sand production rate versus time as well as the change of porosity versus space and time. In this paper, the Geomechanical model coupled with Hydro – Mechanical model is applied to calibrate the empirical parameters.
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Fischer, K., and A. Henk. "A workflow for building and calibrating 3-D geomechanical models &ndash a case study for a gas reservoir in the North German Basin." Solid Earth 4, no. 2 (October 15, 2013): 347–55. http://dx.doi.org/10.5194/se-4-347-2013.
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Abstract. The optimal use of conventional and unconventional hydrocarbon reservoirs depends, amongst other things, on the local tectonic stress field. For example, wellbore stability, orientation of hydraulically induced fractures and – especially in fractured reservoirs – permeability anisotropies are controlled by the present-day in situ stresses. Faults and lithological changes can lead to stress perturbations and produce local stresses that can significantly deviate from the regional stress field. Geomechanical reservoir models aim for a robust, ideally "pre-drilling" prediction of the local variations in stress magnitude and orientation. This requires a numerical modelling approach that is capable to incorporate the specific geometry and mechanical properties of the subsurface reservoir. The workflow presented in this paper can be used to build 3-D geomechanical models based on the finite element (FE) method and ranging from field-scale models to smaller, detailed submodels of individual fault blocks. The approach is successfully applied to an intensively faulted gas reservoir in the North German Basin. The in situ stresses predicted by the geomechanical FE model were calibrated against stress data actually observed, e.g. borehole breakouts and extended leak-off tests. Such a validated model can provide insights into the stress perturbations in the inter-well space and undrilled parts of the reservoir. In addition, the tendency of the existing fault network to slip or dilate in the present-day stress regime can be addressed.
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Burgdorff, Katharine, David Castillo, Adrian White, Jon Rowse, Gavin Douglas, and Mike Dow. "Near real-time geomechanical modelling update and completion optimisation in the fold belt area of PNG: a case study with Oil Search Ltd." APPEA Journal 50, no. 2 (2010): 725. http://dx.doi.org/10.1071/aj09089.
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Collecting high-resolution image data in the majority of currently-drilled wells in the Papuan Fold Belt area has substantially improved our knowledge of the subsurface. A major contribution comes from the observation that the contemporary stress field and the pore pressure environment in the fold belt area are non-uniform. Comprehensive analysis of high-quality LWD images through the overburden has combated uncertainties brought about by the heterogeneity in the stresses and pore pressure. These data have been especially important when updating or constraining a geomechanical model in near real-time for the purpose of providing wellbore stability and completion recommendations. The geomechanical model unique to a particular part of the structure has been combined with finite-element modelling to help identify the optimal completion strategy for the reservoir sands in a number of wells. Recently, the near real-time geomechanical analysis has been used to quickly identify the optimal perforation direction in the reservoir in order to minimise the risk of solids production during completion.Essential data sources for the modelling include LWD images from the reservoir to confirm stress orientations and LWD density data and petrophysical analysis to accurately determine sand strength (UCS). A quick-look analysis uses the calculated UCS profile and the geomechanical model to identify, and therefore avoid perforating, any weak sections of the reservoir. Doing so hopefully mitigates the risk of solids production. This paper outlines the workflow and displays some results from the Papuan Fold Belt area.
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Liu, Qin, Shu Cai Li, Li Ping Li, Yan Zhao, and Xiao Shuai Yuan. "Development of Geomechanical Model Similar Material for Soft Rock Tunnels." Advanced Materials Research 168-170 (December 2010): 2249–53. http://dx.doi.org/10.4028/www.scientific.net/amr.168-170.2249.
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Liangshui Tunnel of Lanzhou-Chongqing railway and Tianpingshan Tunnel of Guiyang-Guangzhou railway are the background work. Combining the construction process mechanics of soft rock, uniaxial compressive test, Brazilian test and direct shear test under different material proportion are carried out. After comparing and analyzing the basic physical and mechanical parameters of original rock and model materials, the similar materials for soft rock tunnel are attained. The effect of component proportion on material properties is analyzed. These results provide reliable material guarantee for model test of construction process mechanics in soft rock tunnels.
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Fadeeva, V. A., V. A. Pavlov, M. D. Subbotin, D. A. Polyakov, N. A. Pavlyukov, A. Yu Kudymov, and M. I. Samoilov. "USING A PRELIMINARY 1D GEOMECHANICAL MODEL FOR CORE RESEARCH PLANNING." Geology, Geophysics and Development of Oil and Gas Fields, no. 7 (2020): 29–35. http://dx.doi.org/10.30713/2413-5011-2020-7(343)-29-35.
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Sosa Massaro, Agustin, D. Nicolas Espinoza, Marcelo Frydman, Silvia Barredo, and Sergio Cuervo. "Analyzing a suitable elastic geomechanical model for Vaca Muerta Formation." Journal of South American Earth Sciences 79 (November 2017): 472–88. http://dx.doi.org/10.1016/j.jsames.2017.09.011.
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Belyakov, V. G., A. V. Leont'ev, N. A. Miroshnichenko, and E. V. Rubtsova. "Block Model for Realization of Prediction Component in Geomechanical Monitoring." Journal of Mining Science 39, no. 4 (July 2003): 338–53. http://dx.doi.org/10.1023/b:jomi.0000023185.31882.0a.
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