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Journal articles on the topic 'Reservoir simulation'
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1
Iqbal, Khairul, Moh Abduh, and ,. Variadi. "Simulation of Multi Reservoir Operation Rules with Interconnected Tunnel and Water Transfer." Aceh International Journal of Science and Technology 12, no. 2 (September 5, 2023): 285–96. http://dx.doi.org/10.13170/aijst.12.2.32532.
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The multi-reservoir operation rules require accuracy in developing its technical parameters. This is done to prevent operational failure in one of the reservoirs. The water transfer concept is to manage the water resources distribution between the receiving watershed and the donor watershed. The availability of transferable water must be prioritized, meeting the water demand of the donor reservoir. Storage capacity in both reservoirs aims to meet water demand, especially in the recipient. The elevation of the interconnecting tunnel is the minimum limit for water use in simulation. The interconnected tunnels' location and capacity will determine the multi-reservoir's operation rule. The interconnected tunnel in the Rukoh Tiro reservoir transfers water in the operation of the two reservoirs. The simulation is carried out in three seasons, considering the inflow of each watershed, the reservoir's downstream water demand, and the reservoir's technical conditions. The simulation results of the Rukoh Tiro reservoir operated simultaneously in all three seasons show that the fulfillment of irrigation water demand can reach 100% as needed. The water transfer process through interconnected tunnels occurs throughout the year. The reservoir operating rule is expected to be a reference in the multi-reservoir operation to obtain an optimal reservoir operating rule.
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Ghassemzadeh, Shahdad, Maria Gonzalez Perdomo, Manouchehr Haghighi, and Ehsan Abbasnejad. "Deep net simulator (DNS): a new insight into reservoir simulation." APPEA Journal 60, no. 1 (2020): 124. http://dx.doi.org/10.1071/aj19093.
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Reservoir simulation plays a vital role as a diagnostics tool to better understand and predict a reservoir’s behaviour. The primary purpose of running a reservoir simulation is to replicate reservoir performance under different production conditions; therefore, the development of a reliable and fast dynamic reservoir model is a priority for the industry. In each simulation, the reservoir is divided into millions of cells, with fluid and rock attributes assigned to each cell. Based on these attributes, flow equations are solved through numerical methods, resulting in an excessively long processing time. Given the recent progress in machine learning methods, this study aimed to further investigate the possibility of using deep learning in reservoir simulations. Throughout this paper, we used deep learning to build a data-driven simulator for both 1D oil and 2D gas reservoirs. In this approach, instead of solving fluid flow equations directly, a data-driven model instantly predicts the reservoir pressure using the same input data of a numerical simulator. Datasets were generated using a physics-based simulator. It was found that for the training and validation sets, the mean absolute percentage error (MAPE) was less than 15.1% and the correlation coefficient, R2, was more than 0.84 for the 1D oil reservoirs, while for the 2D gas reservoir MAPE < 0.84% and R2 ≈1. Furthermore, the sensitivity analysis results confirmed that the proposed approach has promising potential (MAPE < 5%, R2 > 0.9). The results agreed that the deep learning based, data-driven model is reasonably accurate and trustworthy when compared with physics-derived models.
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Vanderkelen, Inne, Shervan Gharari, Naoki Mizukami, Martyn P. Clark, David M. Lawrence, Sean Swenson, Yadu Pokhrel, Naota Hanasaki, Ann van Griensven, and Wim Thiery. "Evaluating a reservoir parametrization in the vector-based global routing model mizuRoute (v2.0.1) for Earth system model coupling." Geoscientific Model Development 15, no. 10 (June 1, 2022): 4163–92. http://dx.doi.org/10.5194/gmd-15-4163-2022.
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Abstract. Human-controlled reservoirs have a large influence on the global water cycle. While global hydrological models use generic parameterizations to model dam operations, the representation of reservoir regulation is still lacking in many Earth system models. Here we implement and evaluate a widely used reservoir parametrization in the global river-routing model mizuRoute, which operates on a vector-based river network resolving individual lakes and reservoirs and is currently being coupled to an Earth system model. We develop an approach to determine the downstream area over which to aggregate irrigation water demand per reservoir. The implementation of managed reservoirs is evaluated by comparing them to simulations ignoring inland waters and simulations with reservoirs represented as natural lakes using (i) local simulations for 26 individual reservoirs driven by observed inflows and (ii) global-domain simulations driven by runoff from the Community Land Model. The local simulations show the clear added value of the reservoir parametrization, especially for simulating storage for large reservoirs with a multi-year storage capacity. In the global-domain application, the implementation of reservoirs shows an improvement in outflow and storage compared to the no-reservoir simulation, but a similar performance is found compared to the natural lake parametrization. The limited impact of reservoirs on skill statistics could be attributed to biases in simulated river discharge, mainly originating from biases in simulated runoff from the Community Land Model. Finally, the comparison of modelled monthly streamflow indices against observations highlights that including dam operations improves the streamflow simulation compared to ignoring lakes and reservoirs. This study overall underlines the need to further develop and test runoff simulations and water management parameterizations in order to improve the representation of anthropogenic interference of the terrestrial water cycle in Earth system models.
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Su, Chang, Gang Zhao, Yee-Chung Jin, and Wanju Yuan. "Semi-Analytical Modeling of Geological Features Based Heterogeneous Reservoirs Using the Boundary Element Method." Minerals 12, no. 6 (May 24, 2022): 663. http://dx.doi.org/10.3390/min12060663.
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The objective of this work is to innovatively apply the boundary element method (BEM) as a general modeling strategy to deal with complicated reservoir modeling problems, especially those related to reservoir heterogeneity and fracture systems, which are common challenges encountered in the practice of reservoir engineering. The transient flow behaviors of reservoirs containing multi-scale heterogeneities enclosed by arbitrarily shaped boundaries are modeled by applying BEM. We demonstrate that a BEM-based simulation strategy is capable of modeling complex heterogeneous reservoirs with robust solutions. The technology is beneficial in making the best use of geological modeling information. The governing differential operator of fluid flow within any locally homogeneous domain is solved along its boundary. The discretization of a reservoir system is only made on the corresponding boundaries, which is advantageous in closely conforming to the reservoir’s geological description and in facilitating the numerical simulation and computational efforts because no gridding within the flow domain is needed. Theoretical solutions, in terms of pressure and flow rate responses, are validated and exemplified for various reservoir–well systems, including naturally fractured reservoirs with either non-crossing fractures or crossing fractures; fully compartmentalized reservoirs; and multi-stage, fractured, horizontal wells with locally stimulated reservoir volumes (SRVs) around each stage of the fracture, etc. A challenging case study for a complicated fracture network system is examined. This work demonstrates the significance of adapting the BEM strategy for reservoir simulation due to its flexibility in modeling reservoir heterogeneity, analytical solution accuracy, and high computing efficiency, in reducing the technical gap between reservoir engineering practice and simulation capacity.
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Hu, Liangming, Xu Yang, Qian Li, and Shuyu Li. "Numerical Simulation and Risk Assessment of Cascade Reservoir Dam-Break." Water 12, no. 6 (June 17, 2020): 1730. http://dx.doi.org/10.3390/w12061730.
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Despite the fact that cascade reservoirs are built in a large number of river basins nowadays, there is still an absence of studies on sequential embankment dam-break in cascade reservoirs. Therefore, numerical simulations and risk analyses of cascade reservoir dam-break are of practical engineering significance. In this study, by means of contacting the hydraulic features of upstream and downstream reservoirs with flood routing simulation (FRS) and flood-regulating calculation (FRC), a numerical model for the whole process of cascade reservoir breaching simulation (CRBS) is established based on a single-embankment dam-break model (Dam Breach Analysis—China Institute of Water Resources and Hydropower Research (DB-IWHR)). In a case study of a fundamental cascade reservoir system, in the upstream Tangjiashan barrier lake and the downstream reservoir II, the whole process of cascade reservoir dam-break is simulated and predicted under working schemes of different discharge capacities, and the risk of cascading breaching was also evaluated through CRBS. The results show that, in the dam-break of Tangjiashan barrier lake, the calculated values of the peak outflow rate are about 10% more than the recorded data, which are in an acceptable range. In the simulation of flood routing, the dam-break flood arrived at the downstream reservoir after 3 h. According to the predicted results of flood-regulating calculations and the dam-break simulation in the downstream reservoir, the risk of sequential dam-break can be effectively reduced by setting early warnings to decrease reservoir storage in advance and adding a second discharge tunnel to increase the discharge capacity. Alongside the simulation of flood routing and flood regulation, the whole process of cascade dam-break was completely simulated and the results of CRBS tend to be more reasonable; CRBS shows the great value of engineering application in the risk assessment and flood control of cascade reservoirs as an universal numerical prediction model.
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Cheong, T. S., I. Ko, and J. W. Labadie. "Development of multi-objective reservoir operation rules for integrated water resources management." Journal of Hydroinformatics 12, no. 2 (November 14, 2009): 185–200. http://dx.doi.org/10.2166/hydro.2009.054.
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Real-time monitoring, databases, optimization models and visualization tools have been integrated into a Decision Support System (DSS) for optimal water resources management of two water supply reservoirs, the Daechung Reservoir and the Yongdam Reservoir of the Geum River basin, Daejeon, Korea. The KModSim as a DSS has been designed to provide information on current reservoir conditions to operational staff and to help in making decisions for short- and long-term management. For the physical calibration, the network simulations in seasonal water allocation of both reservoirs are performed for 23 years from January 1 1983 to June 30 2006. Linear and nonlinear operating rules are developed by using the actual reservoir operation data obtained from both reservoirs which are then used in KModSim by the hydrologic state method to estimate optimized target storages of both reservoirs. For validation of hydrologic states in KModSim and scenario testing for the management simulations, the optimal network simulation for the seasonal water allocations from October 1 2002 to June 30 2006 were also performed. The results' simulation by new rules fit the measured actual reservoir storage and represent well the various outflow discharge curves measured at the gauging stations of Geum River. The developed operating rules are proven to be superior in explaining actual reservoir operation as compared to the simulated target storages by existing optimization models.
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Shar, Abdul Majeed, Waheed Ali Abro, Aftab Ahmed Mahesar, and Kun Sang Lee. "Simulation Study to Evaluate the Impact of Fracture Parameters on Shale Gas Productivity." April 2020 39, no. 2 (April 1, 2020): 432–42. http://dx.doi.org/10.22581/muet1982.2002.19.
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The production from shale gas reservoirs has significantly increased due to technological advancements. The shale gas reservoirs are very heterogeneous and the heterogeneity has a significant effect on the quality and productivity of reservoirs. Hence, it is essential to study the behavior of such reservoirs for accurate modelling and performance prediction. To evaluate the impact of fracture parameters on shale gas reservoir productivity using CMG (Computer Modelling Group) stars simulation software was the main objective of this study. In this paper, a comprehensive analysis considering an example shale gas reservoir was conducted for production performance analysis considering uniform and non-uniform fractures configurations. Several simulations were performed by considering the multi-stage hydraulically fractured reservoir. The sensitivities conducted includes the different cases of moderate and severe heterogeneity along with variable fractures half-length, effect of changing fracture spacing, variable fracture conductivities. The simulation results showed that by increasing conductivity of fracture increases the gas production rate significantly. Moreover, cases of reservoir permeability heterogeneity were analyzed which show the significant effect on gas rate and on cumulative gas production. The results of this study can be used to improve the effectiveness in designing and developing of shale gas reservoirs and also to improve the accuracy of analyzing heterogeneous shale gas reservoir performance.
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Jaiswal, Shashi Kant. "Simulation Of Reservoir Operation In A Multi Reservoir System." Journal of University of Shanghai for Science and Technology 23, no. 08 (August 14, 2021): 451–56. http://dx.doi.org/10.51201/jusst/21/08423.
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The present study aims to apply simulation software MIKE Basin for the operation of reservoirs of Mahanadi Reservoir Project (MRP) Complex. MRP complex is a multipurpose multi reservoir system. Simulation is a technique by which we emulate the behavior of a system. Simulation is a very powerful technique in analyzing most complex water resource system in detail for performance evaluation. Reservoir operation study has been done for data of 34 years. The results extracted from the study indicated that the performance of simulation model MIKE Basin is satisfactory.
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Kaliszewski, A. B. "RESERVOIR SIMULATION FOR RESERVOIR MANAGEMENT." APPEA Journal 26, no. 1 (1986): 397. http://dx.doi.org/10.1071/aj85034.
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The Hutton reservoir in the Merrimelia Field (Cooper-Eromanga Basin) was the subject of a 3-D reservoir simulation study. The primary objective of the study was to develop a reservoir management tool for evaluating the performance of the field under various depletion options.The study confirmed that the ultimate oil recovery from this strong water drive reservoir was not adversely affected by increasing total fluid offtake rate. However, any decisions regarding changes to the depletion scheme such as increasing production rates, if based solely on computer simulation results, should be viewed with caution. Careful monitoring of any changes to the depletion philosophy and checking of actual data against simulation predictions are essential to ensure that oil production rate and ultimate recovery are optimised.The model assisted in evaluating the economics of development drilling. While the simulation results are dependent on the validity of geological mapping, the model was useful in confirming that, due to very high transmissibility in the Hutton reservoir, additional wells would only accelerate production rather than increase ultimate recovery. The issue of drilling wells thus became one of balancing the benefits of accelerating production against the geological risk associated with that well.Interaction between the reservoir engineer and various disciplines, particularly development geology, is critical in the development and application of a good working simulation model. This was found to be especially important during the history matching phase in the study. If engineers and development geologists can learn more of the others' discipline and appreciate the role that each has to play in simulation studies, the validity of such models can only be improved.The paper addresses a number of the pitfalls commonly encountered in application of reservoir simulation results.
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Carpenter, Chris. "Approach Couples Reservoir Simulation With Wellbore Model for Horizontal Wells." Journal of Petroleum Technology 74, no. 01 (January 1, 2022): 64–67. http://dx.doi.org/10.2118/0122-0064-jpt.
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This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 203977, “Coupling a Geomechanical Reservoir and Fracturing Simulator With a Wellbore Model for Horizontal Injection Wells,” by Shuang Zheng, SPE, and Mukul Sharma, SPE, The University of Texas at Austin. The paper has not been peer reviewed. Reservoir cooling during waterflooding or waste-water injection can alter the reservoir stress field significantly by thermoporoelastic effects. Colloidal particles in the injected water decrease the matrix permeability and build up the injection pressure. Fractures may initiate and propagate from injectors. These fractures are of great concern for environmental reasons and are a strong influence on reservoir sweep and oil recovery. The complete paper introduces methods to fully couple reservoir simulation with wellbore flow models in fractured injection wells. Introduction In this study, a fully integrated 3D geomechanical thermal reservoir simulator is presented. This simulator is fully coupled with a wellbore model and allows fracture propagation. The model accounts for multiphase flow, solid mechanics, thermal stresses, filtration, and fracture growth in coupled reservoir- fracture-wellbore domains and can be used for simulations in both conventional and unconventional reservoirs. The simulator allows study of induced fracture propagation in cased- and openhole injectors while fully accounting for thermoporoelastic and particle-filtration effects. It also allows study of hydraulic fracture propagation in unconventional reservoirs considering the complex wellbore dynamics. The complete paper provides a practical simulation tool to maximize well injectivity while minimizing environmental risks, and to analyze and optimize the completion design in unconventional reservoirs.
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Li, Qingping, Shuxia Li, Shuyue Ding, Zhenyuan Yin, Lu Liu, and Shuaijun Li. "Numerical Simulation of Gas Production and Reservoir Stability during CO2 Exchange in Natural Gas Hydrate Reservoir." Energies 15, no. 23 (November 27, 2022): 8968. http://dx.doi.org/10.3390/en15238968.
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The prediction of gas productivity and reservoir stability of natural gas hydrate (NGH) reservoirs plays a vital role in the exploitation of NGH. In this study, we developed a THMC (thermal-hydrodynamic-mechanical-chemical) numerical model for the simulation of gas production behavior and the reservoir response. The model can describe the phase change, multiphase flow in porous media, heat transfer, and deformation behavior during the exploitation of NGH reservoirs. Two different production scenarios were employed for the simulation: depressurization and depressurization coupled with CO2 exchange. The simulation results suggested that the injection of CO2 promotes the dissociation of NGH between the injection well and the production well compared with depressurization only. The cumulative production of gas and water increased by 27.88% and 2.90%, respectively, based on 2000 days of production simulation. In addition, the subsidence of the NGH reservoir was lower in the CO2 exchange case compared with the single depressurization case for the same amount of cumulative gas production. The simulation results suggested that CO2 exchange in NGH reservoirs alleviates the issue of reservoir subsidence during production and maintains good reservoir stability. The results of this study can be used to provide guidance on field production from marine NGH reservoirs.
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Huang, Lingxiao, Qiao Qiao, Lanxiang Zheng, Libo Liu, Wenjuan Zhao, Hefang Jing, and Chunguang Li. "Numerical simulation of three dimensional flow in Yazidang Reservoir based on image processing." Journal of Intelligent & Fuzzy Systems 39, no. 2 (August 31, 2020): 1591–600. http://dx.doi.org/10.3233/jifs-179932.
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In order to study the water flow movement of the Yazidang Reservoir, this paper generates the initial terrain for the researched water area with the image stitching technology and image edge detection technology, establishes a 3D k - ɛ mathematical model, solves the equations discretely by FVM and SIMPLEC algorithms, studies the numerical simulation of the water flow movement of the reservoir under four working conditions, and analyzes the flow field on the surface and at the bottom of the reservoir. The results show the improved terrain pre-processing accuracy and efficiency of the researched water area and the rationality of the water flow field and rate simulation results, which means that the established 3D turbulence mathematical model can be applied to the numerical simulation of the reservoirs similar to the Yazidang Reservoir. The numerical simulation of 3D turbulence in Yazidang Reservoir provides a theoretical basis and practical application value for the numerical simulation of similar reservoirs.
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Mu, Song Ru, and Shi Cheng Zhang. "Numerical Simulation of Shale Gas Production." Advanced Materials Research 402 (November 2011): 804–7. http://dx.doi.org/10.4028/www.scientific.net/amr.402.804.
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Shale gas reservoirs require a large fracture network to maximize well performance. Microseismic fracture mapping has shown that large fracture networks can be generated in many shale reservoirs. The application of microseismic fracture mapping measurements requires estimation of the structure of the complex hydraulic fracture or the volume of the reservoir that has been stimulated by the fracture treatment. There are three primary approaches used to incorporate microseismic measurements into reservoir simulation models: discrete modeling of the complex fracture network, wire-mesh model, and dual porosity model. This paper discuss the different simulation model, the results provided insights into effective stimulation designs and flow mechanism for shale gas reservoirs.
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Sriworamas, Krit, Anongrit Kangrang, Teerawat Thongwan, and Haris Prasanchum. "Optimal Reservoir of Small Reservoirs by Optimization Techniques on Reservoir Simulation Model." Advances in Civil Engineering 2021 (June 15, 2021): 1–14. http://dx.doi.org/10.1155/2021/6625743.
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Reservoir rule curves are essential rules for store activity. This investigation connected the Genetic Algorithm, Firefly Algorithm, Bat Algorithm, Flower Pollination Algorithm, and Tabu Search Algorithm associated with the store reproduction model to look through the ideal supply standard bends, utilizing the Huay Ling Jone and Huay Sabag supplies situated in Yasothorn Province, Thailand, as the contextual investigation. Memorable inflow information of the two repositories were utilized in this investigation, and 1,000 examples of engineered inflows of stores were utilized to recreate the repository activity framework for assessing the acquired principle bends as displayed as far as water circumstances. Circumstances of water lack and abundance water appeared as far as the recurrence extent and length. The outcomes demonstrated that GA, FA, BA, FPA, and TS associated with the reservoir simulation model could give the ideal principle bends which better moderate the drought and flood circumstances contrasted and current guideline bends.
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Fu, Qiang, Zhouyuan Zhu, Junjian Li, Hongmei Jiao, Shuoliang Wang, Huiyun Wen, and Yongfei Liu. "Numerical Reservoir Simulation of Supercritical Multi-Source and Multi-Component Steam Injection for Offshore Heavy Oil Development." Processes 12, no. 1 (January 18, 2024): 216. http://dx.doi.org/10.3390/pr12010216.
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We present the workflow for numerical reservoir simulation of supercritical multi-source and multi-component steam injection for offshore heavy oil development. We have developed unique techniques in a commercial reservoir simulator to implement the thermal properties of supercritical multi-source and multi-component steam, the pyrolysis chemical reactions, the temperature-dependent relative permeability, and the process of partially dissolving the sandstone rock to enhance the matrix permeability in a commercial reservoir simulator. Simulations are conducted on the type pattern reservoir model, which represents one of the heavy oil fields in CNOOC’s Bohai Bay oil field. Simulation input parameters are calibrated based on laboratory experiments conducted for supercritical multi-source and multi-component steam injection. Simulation results have shown clear improvements in injecting supercritical multi-source and multi-component steam in offshore heavy oil reservoirs compared to the normal steam injection process using subcritical steam. This serves as a workflow for implementing a numerical simulation of the novel supercritical multi-source and multi-component steam injection recovery process.
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Asadullah, M., P. Behrenbruch, and S. Pham. "RESERVOIR SIMULATION—UPSCALING, STREAMLINES AND PARALLEL COMPUTING." APPEA Journal 47, no. 1 (2007): 199. http://dx.doi.org/10.1071/aj06013.
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Simulation of petroleum reservoirs is becoming more and more complex due to increasing necessity to model heterogeneity of reservoirs for accurate reservoir performance prediction. With high oil prices and less easy oil, accurate reservoir management tools such as simulation models are in more demand than ever before. The aim is to capture and preserve reservoir heterogeneity when changing over from a detailed geocellular model to a flow simulation model, minimising errors when upscaling and preventing excessive numerical dispersion by employing variable and innovative grids, as well as improved computational algorithms.For accurate and efficient simulation of large-scale models there are essentially three choices: upscaling, which involves averaging of parameters for several blocks, resulting in a coarser model that executes faster; the use of streamline simulation, which uses a more optimal grid, combined with a different computational algorithm for increased efficiency; and, the use of parallel computing techniques, which use superior hardware configurations for efficiency gains. With uncertainty screening of various multiple geostatistical realisations and investigation of alternative development scenarios— now commonplace for determining reservoir performance—computational efficiency and accuracy in modelling are paramount. This paper summarises the main techniques and methodologies involved in considering geocellular models for flow simulation of reservoirs, commenting on advantages and disadvantages among the various possibilities. Starting with some historic comments, the three modes of simulation are reviewed and examples are given for illustrative purposes, including a case history for the Bayu-Undan Field, Timor Sea.
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Chen, Pan Pan, Jun Xie, Cun Lei Li, Meng Qi Wang, Yi Dan Liu, and Bai Chuan Li. "Application of Facies-Controlled Physical Property Modeling in Oubei Block, Jinhu Depression." Applied Mechanics and Materials 522-524 (February 2014): 1359–62. http://dx.doi.org/10.4028/www.scientific.net/amm.522-524.1359.
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Three dimensional (3D) models provide insights into the distribution, external and internal geometry of the reservoirs. The core description shows that the fourth segment of Funing Formation (E1f4), Oubei Block, Jinhu Depression mainly develop delta front subfacies which included underwater distributary channel, mouth bar, sand sheet and so on. Well data and structural maps were integrated to build 3D structure model and sedimentary microfacies model of Oubei reservoirs using stochastic simulations with geometry data. The result of facies-controlled property model can reasonably reflect reservoir characteristics in detail, providing a reliable geological model for late reservoir adjustment and valuable reference for numerical reservoir simulation as well.
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Liu, Zhen Yu, Tian Tian Cai, Hu Zhen Wang, and Cheng Yu Zhang. "Numerical Simulation of Stimulated Volume in Low-Permeability Reservoir." Advanced Materials Research 734-737 (August 2013): 1415–19. http://dx.doi.org/10.4028/www.scientific.net/amr.734-737.1415.
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There is an increasing focus on the effective methods to develop low-permeability reservoirs, especially for ultra-low permeability reservoirs. It is hard to achieve the expected stimulation effect only on the traditional single fracturing, because of the poor supply ability from the matrix to fracture in low-permeability reservoirs. Volume stimulating to reservoir, achieving short distance from matrix to fracture because of producing fracture network. So the volume fracturing technology proposed for increasing oil or gas production, this technology is suitable for low porosity and low permeability reservoir. The conventional simulation method can't describe the complex fracture network accurately,but this paper established hydraulic fracturing complex fracture model based on the finite element numerical simulation method , making the simulated complex fracture more close to the real description,it can accurately describe the flow state in the reservoir and cracks.It has an important reference value to the low permeability reservoirs.
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Araújo, E. A., L. C. Batista, E. A. Araújo, D. N. N. Silva, C. R. S. Lucas, and P. T. P. Aum. "STEAM INJECTION NUMERICAL ANALYSES IN HEAVY OIL RESERVOIRS." Brazilian Journal of Petroleum and Gas 16, no. 4 (January 3, 2023): 161–68. http://dx.doi.org/10.5419/bjpg2022-0013.
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Thermal recovery methods aim to reduce oil viscosity, thus, increasing its mobility and enhancing its recovery. Reservoir numerical simulation is a powerful tool for predicting reservoir production performance under different operational parameters. One critical point is understanding the relationship between flow rate and recovery factor. This study aims to analyze steam injection into the porous medium in heavy oil reservoirs by numerical simulation using a commercial multiphase flow simulator to simulate the continuous steam injection process. The homogeneous reservoir was built with 14,375 cells. The fluid model has characteristics of onshore Northeastern Brazilian fields. Simulations were performed over a period of 16 years, and results indicate that the steam injection promotes oil production anticipation but reaches a limit as the flow rate increases. The results presented can contribute to improve the understanding of the effects of flow rate in a heavy oil reservoir.
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Dogru, Ali H. "Megacell Reservoir Simulation." Journal of Petroleum Technology 52, no. 05 (May 1, 2000): 54–60. http://dx.doi.org/10.2118/57907-jpt.
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McVay, D. A., P. A. Bastian, and B. D. Epperson. "Interactive Reservoir Simulation." SPE Computer Applications 3, no. 06 (November 1, 1991): 7–11. http://dx.doi.org/10.2118/22309-pa.
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O'sullivan, M. J. "Geothermal reservoir simulation." International Journal of Energy Research 9, no. 3 (July 1985): 319–32. http://dx.doi.org/10.1002/er.4440090309.
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Ayache, Simon V., Violaine Lamoureux-Var, Pauline Michel, and Christophe Preux. "Reservoir Simulation of Hydrogen Sulfide Production During a Steam-Assisted-Gravity-Drainage Process by Use of a New Sulfur-Based Compositional Kinetic Model." SPE Journal 22, no. 01 (August 3, 2016): 080–93. http://dx.doi.org/10.2118/174441-pa.
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Summary Steam injection is commonly used as a thermal enhanced-oil-recovery (EOR) method because of its efficiency for recovering hydrocarbons, especially from heavy-oil and bitumen reservoirs. Reservoir models simulating this process describe the thermal effect of the steam injection, but generally neglect the chemical reactions induced by the steam injection and occurring in the reservoir. In particular, these reactions can lead to the generation and production of the highly toxic and corrosive acid gas hydrogen sulfide (H2S). The overall objective of this paper is to quantitatively describe the chemical aquathermolysis reactions that occur in oil-sands reservoirs undergoing steam injections and to provide oil companies with a numerical model for reservoir simulators to forecast the H2S-production risks. For that purpose, a new sulfur-based compositional kinetic model has been developed to reproduce the aquathermolysis reactions in the context of reservoir modeling. It is derived from results gathered on an Athabasca oil sand from previous laboratory aquathermolysis experiments. In particular, the proposed reactions model accounts for the formation of H2S issued from sulfur-rich heavy oils or bitumen, and predicts the modification of the resulting oil saturate, aromatic, resin, and asphaltene (SARA) composition vs. time. One strength of this model is that it is easily calibrated against laboratory-scale experiments conducted on an oil-sand sample. Another strength is that its calibration is performed while respecting the constraints imposed by the experimental data and the theoretical principles. In addition, in this study no calibration was needed at reservoir scale against field-production data. In the paper, the model is first validated with laboratory-scale simulations. The thermokinetic modeling is then coupled with a 2D reservoir simulation of a generic steam-assisted gravity drainage (SAGD) process applied on a generic Athabasca oil-sand reservoir. This formulation allows investigating the H2S generation at reservoir scale and quantifying its production. The H2S- to bitumen-production ratio against time computed by the reservoir simulation is found to be consistent with production data from SAGD operations in Athabasca, endorsing the proposed methodology.
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Liu, Chen, Wensheng Zhou, Junzhe Jiang, Fanjie Shang, Hong He, and Sen Wang. "Remaining Oil Distribution and Development Strategy for Offshore Unconsolidated Sandstone Reservoir at Ultrahigh Water-Cut Stage." Geofluids 2022 (September 6, 2022): 1–11. http://dx.doi.org/10.1155/2022/6856298.
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Due to the influence of long-term waterflooding, the reservoir physical properties and percolation characteristics tend to change greatly in offshore unconsolidated sandstone reservoirs at ultrahigh water-cut stage, which can affect the remaining oil distribution. Remaining oil characterization and proper development strategy-making are of vital importance to achieve high-efficiency development of mature reservoirs. The present numerical simulation method is difficult to apply in reservoir development due to the problems of noncontinuous characterization and low computational efficiency. Based on the extended function of commercial numerical simulator, the time-varying equivalent numerical simulation method of reservoir physical properties was established, and the research of numerical simulation of X offshore oilfield with 350,000 effective grids was completed. The results show that the time-varying reservoir properties have a significant impact on the distribution of remaining oil in ultrahigh water-cut reservoir. Compared with the conventional numerical simulation, the remaining oil at the top of main thick reservoir in X oilfield has increased by 18.5% and the remaining oil in the low-permeability zone at the edge of the nonmain reservoir has increased by 27.3%. The data of coring well and the implementation effect of measures in the X oilfield are consistent with the recognition of numerical simulation, which proves the rationality of numerical simulation results. The new method is based on a mature commercial numerical simulator, which is easy to operate and has reliable results.
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Dogru, A. H., H. A. Sunaidi, L. S. Fung, W. A. Habiballah, N. Al-Zamel, and K. G. Li. "A Parallel Reservoir Simulator for Large-Scale Reservoir Simulation." SPE Reservoir Evaluation & Engineering 5, no. 01 (February 1, 2002): 11–23. http://dx.doi.org/10.2118/75805-pa.
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Summary A new parallel, black-oil-production reservoir simulator (Powers**) has been developed and fully integrated into the pre- and post-processing graphical environment. Its primary use is to simulate the giant oil and gas reservoirs of the Middle East using millions of cells. The new simulator has been created for parallelism and scalability, with the aim of making megacell simulation a day-to-day reservoir-management tool. Upon its completion, the parallel simulator was validated against published benchmark problems and other industrial simulators. Several giant oil-reservoir studies have been conducted with million-cell descriptions. This paper presents the model formulation, parallel linear solver, parallel locally refined grids, and parallel well management. The benefits of using megacell simulation models are illustrated by a real field example used to confirm bypassed oil zones and obtain a history match in a short time period. With the new technology, preprocessing, construction, running, and post-processing of megacell models is finally practical. A typical history- match run for a field with 30 to 50 years of production takes only a few hours. Introduction With the development of early parallel computers, the attractive speed of these computers got the attention of oil industry researchers. Initial questions were concentrated along these lines:Can one develop a truly parallel reservoir-simulator code?What type of hardware and programming languages should be chosen? Contrary to seismic, it is well known that reservoir simulator algorithms are not naturally parallel; they are more recursive, and variables display a strong dependency on each other (strong coupling and nonlinearity). This poses a big challenge for the parallelization. On the other hand, if one could develop a parallel code, the speed of computations would increase by at least an order of magnitude; as a result, many large problems could be handled. This capability would also aid our understanding of the fluid flow in a complex reservoir. Additionally, the proper handling of the reservoir heterogeneities should result in more realistic predictions. The other benefit of megacell description is the minimization of upscaling effects and numerical dispersion. The megacell simulation has a natural application in simulating the world's giant oil and gas reservoirs. For example, a grid size of 50 m or less is used widely for the small and medium-size reservoirs in the world. In contrast, many giant reservoirs in the Middle East use a gridblock size of 250 m or larger; this easily yields a model with more than 1 million cells. Therefore, it is of specific interest to have megacell description and still be able to run fast. Such capability is important for the day-to-day reservoir management of these fields. This paper is organized as follows: the relevant work in the petroleum-reservoir-simulation literature has been reviewed. This will be followed by the description of the new parallel simulator and the presentation of the numerical solution and parallelism strategies. (The details of the data structures, well handling, and parallel input/output operations are placed in the appendices). The main text also contains a brief description of the parallel linear solver, locally refined grids, and well management. A brief description of megacell pre- and post-processing is presented. Next, we address performance and parallel scalability; this is a key section that demonstrates the degree of parallelization of the simulator. The last section presents four real field simulation examples. These example cases cover all stages of the simulator and provide actual central processing unit (CPU) execution time for each case. As a byproduct, the benefits of megacell simulation are demonstrated by two examples: locating bypassed oil zones, and obtaining a quicker history match. Details of each section can be found in the appendices. Previous Work In the 1980s, research on parallel-reservoir simulation had been intensified by the further development of shared-memory and distributed- memory machines. In 1987, Scott et al.1 presented a Multiple Instruction Multiple Data (MIMD) approach to reservoir simulation. Chien2 investigated parallel processing on sharedmemory computers. In early 1990, Li3 presented a parallelized version of a commercial simulator on a shared-memory Cray computer. For the distributed-memory machines, Wheeler4 developed a black-oil simulator on a hypercube in 1989. In the early 1990s, Killough and Bhogeswara5 presented a compositional simulator on an Intel iPSC/860, and Rutledge et al.6 developed an Implicit Pressure Explicit Saturation (IMPES) black-oil reservoir simulator for the CM-2 machine. They showed that reservoir models over 2 million cells could be run on this type of machine with 65,536 processors. This paper stated that computational speeds in the order of 1 gigaflop in the matrix construction and solution were achievable. In mid-1995, more investigators published reservoir-simulation papers that focused on distributed-memory machines. Kaarstad7 presented a 2D oil/water research simulator running on a 16384 processor MasPar MP-2 machine. He showed that a model problem using 1 million gridpoints could be solved in a few minutes of computer time. Rame and Delshad8 parallelized a chemical flooding code (UTCHEM) and tested it on a variety of systems for scalability. This paper also included test results on Intel iPSC/960, CM-5, Kendall Square, and Cray T3D.
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Kang, Zhijiang, Ze Deng, Wei Han, and Dongmei Zhang. "Parallel Reservoir Simulation with OpenACC and Domain Decomposition." Algorithms 11, no. 12 (December 18, 2018): 213. http://dx.doi.org/10.3390/a11120213.
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Parallel reservoir simulation is an important approach to solving real-time reservoir management problems. Recently, there is a new trend of using a graphics processing unit (GPU) to parallelize the reservoir simulations. Current GPU-aided reservoir simulations focus on compute unified device architecture (CUDA). Nevertheless, CUDA is not functionally portable across devices and incurs high amount of code. Meanwhile, domain decomposition is not well used for GPU-based reservoir simulations. In order to address the problems, we propose a parallel method with OpenACC to accelerate serial code and reduce the time and effort during porting an application to GPU. Furthermore, the GPU-aided domain decomposition is developed to accelerate the efficiency of reservoir simulation. The experimental results indicate that (1) the proposed GPU-aided approach can outperform the CPU-based one up to about two times, meanwhile with the help of OpenACC, the workload of the transplant code was reduced significantly by about 22 percent of the source code, (2) the domain decomposition method can further improve the execution efficiency up to 1.7×. The proposed parallel reservoir simulation method is a efficient tool to accelerate reservoir simulation.
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Fan, Shi Ping, Jian Ming Yang, Min Quan Feng, and Bang Min Zheng. "Simulation of Simplified Three-Dimensional Space Flow Velocity Field in Reservoir on the Condition of Unsteady Flow and its Application." Applied Mechanics and Materials 203 (October 2012): 514–18. http://dx.doi.org/10.4028/www.scientific.net/amm.203.514.
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In view of the complexity of the conventional simulation calculation method of three-dimensional flow field for the reservoir, and to analysis of the change of the reservoir’s flow field in flood period, in this paper, based on the unsteady flow numerical calculation, the simulation method for three-dimensional space flow velocity field of the reservoir in flood period was studied and applied to the Wenyuhe Reservoir. First refining the actual extraction of grid, and then having an unsteady flow numerical calculation for the reservoir, finally through layering and stripping the grid, three-dimensional space flow velocity field the reservoir on the condition of unsteady flow has been studied. The results showed that the reservoir velocity along the flow direction is becoming smaller, and surface velocity is fast; with the flow increase gradually, the unsteady flow has a great effect on the flow field of the reservoir’s concave bank. The grid can at will encryption, so the calculation precision can be effectively controlled and the process of simulation is easy to be programmed. The research results can simplify the complexity of the reservoir for three-dimensional numerical simulation, and up to providing theoretical support for reservoir flood control.
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Jiang, Qing, and Pengju Li. "Numerical Simulation of Carbon Oxygen Ratio Logging Response in Natural Gas Hydrate Reservoirs." International Journal of Energy 2, no. 3 (May 22, 2023): 13–16. http://dx.doi.org/10.54097/ije.v2i3.8766.
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In the process of oil and gas field development, in order to identify the gas hydrate reservoir more accurately, we try to use the carbon oxygen ratio spectrum logging technology to study the log response law of this reservoir, and compare it with the reservoir response law to better guide the oil field production. Firstly, the theoretical response law of carbon and oxygen concentration ratio of natural gas hydrate reservoir and oil layer is deduced according to the petrophysical model, and then the response law of carbon and oxygen concentration ratio of two types of reservoirs simulated by Monte Carlo numerical simulation is studied, and the similarity law and difference between the two types of reservoirs are summarized. The results show that the carbon oxygen ratio has a regular change relationship with the porosity and saturation of the reservoir. The carbon oxygen ratio can be used to preliminarily distinguish and qualitatively identify the two types of reservoirs.
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Abdulrazzaq, Tuqa, Hussein Togun, Dalia Haider, Mariam Ali, and Saja Hamadi. "Determining of reservoir fluids properties using PVTP simulation software- a case study of buzurgan oilfield." E3S Web of Conferences 321 (2021): 01018. http://dx.doi.org/10.1051/e3sconf/202132101018.
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The measurement of oil reservoirs and their performance with hydrocarbon reservoirs is used to distinguish the properties of reservoir fluids, which is significant in various reservoir studies. As a result, in the various oil industries, adopting the appropriate methods to obtain accurate property values is very important. The current paper is about a case study of the BUZURGAN Oilfield and how the PVTp software was used to predict phase activity and physical properties. To understand the properties of fluids for the reservoir and phase behavior, the black oil model and the equation of state (EoS) model are used. (Glaso) correlation is used to calculate the bubble point strain, solubility, and formation volume factor. The Beal's correlation was also used to measure viscosity, while the equation of state (EoS) model was used to determine phase behavior and density. Furthermore, the properties of PVT were discovered using the software, and the results were compared to laboratory analysis of PVT, with suitable models being displayed. According to the findings, the used model has the highest saturation pressure, which was chosen for use in reservoir management processes and the preparation of a geological model to reflect the field later. It is clear that the program is appropriate due to the accurate dependence of PVT measurements on laboratory tests in the case that tests are required during the reservoir's productive existence.
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Chang, Te Hsing, Ning Chien Tung, and Fu Ming Chang. "Benefit Assessment of Cut-off Wall Implementation in Daping Groundwater Reservoir." Applied Mechanics and Materials 256-259 (December 2012): 2577–82. http://dx.doi.org/10.4028/www.scientific.net/amm.256-259.2577.
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Groundwater reservoirs aim at saving grounding water from aquifers by means of interception and adjustment. This study adopts numerical model simulation to evaluate the benefit of developing subsurface reservoirs and provides the case of the groundwater reservoir development at Daping region in Dongju Island. Since 2008, this study has been conducting surface geological surveys, geological drilling, surface infiltration experiments, physical experiments on bore specimens, and continuous observation of groundwater level while simultaneously conducting water pumping and slug tests in the field in order to estimate the hydro geological parameters of the site. The development benefit assessment of the groundwater reservoir will also include catchment area, surface land use, calendar year rainfall records and other information. Meanwhile, the FEMWATER numerical model of groundwater will be used to conduct hydrodynamic simulations of the development area. According to the simulation results of pre and post construction of the cut-off wall of the groundwater reservoir, this study could estimate the stable pre and post water volume and the development benefit of the groundwater reservoir can be assessed. According the 3-year unsteady numerical simulation, the results show that the groundwater reservoir can provide approximately 36 m3/day of stable water supply during dry seasons. If a cut-off wall is implemented and the stable water supply could increase 11% to 40 m3/day and raise the average upstream groundwater level of the cut-off wall by 1m, it clearly displays the benefit of the cut-off wall.
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Fujita, Yusuke, Akhil Datta-Gupta, and Michael J. King. "A Comprehensive Reservoir Simulator for Unconventional Reservoirs That Is Based on the Fast Marching Method and Diffusive Time of Flight." SPE Journal 21, no. 06 (May 5, 2016): 2276–88. http://dx.doi.org/10.2118/173269-pa.
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Summary Modeling of fluid flow in unconventional reservoirs requires accurate characterization of complex flow mechanisms because of the interactions between reservoir rock, microfractures, and hydraulic fractures. The pore-size distribution in shale and tight sand reservoirs typically ranges from nanometers to micrometers, resulting in ultralow permeabilities. In such extremely low-permeability reservoirs, desorption and diffusive processes play important roles in addition to heterogeneity-driven convective flows. For modeling shale and tight oil and gas reservoirs, we can compute the well-drainage volume efficiently with a fast marching method (FMM) and by introducing the concept of “diffusive time of flight” (DTOF). Our proposed simulation approach consists of two decoupled steps—drainage-volume calculation and numerical simulation with DTOF as a spatial coordinate. We first calculate the reservoir drainage volume and the DTOF with the FMM, and then the numerical simulation is conducted along the 1D DTOF coordinate. The approach is analogous to streamline modeling whereby a multidimensional simulation is decoupled to a series of 1D simulations resulting in substantial savings in computation time for high-resolution simulation. However, instead of a “convective time of flight” (CTOF), a DTOF is introduced to model the pressure-front propagation. For modeling physical processes, we propose triple continua whereby the reservoir is divided into three different domains: microscale pores (hydraulic fractures and microfractures), nanoscale pores (nanoporous networks), and organic matter. The hydraulic fractures/microfractures primarily contribute to the well production, and are affected by rock compaction. The nanoporous networks contain adsorbed gas molecules, and gas flows into fractures by convection and Knudsen diffusion processes. The organic matter acts as the source of gas. Our simulation approach enables high-resolution flow characterization of unconventional reservoirs because of its efficiency and versatility. We demonstrate the power and utility of our approach with synthetic and field examples.
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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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Ma, Xiaopeng, Jinsheng Zhao, Desheng Zhou, Kai Zhang, and Yapeng Tian. "Deep Graph Learning-Based Surrogate Model for Inverse Modeling of Fractured Reservoirs." Mathematics 12, no. 5 (March 2, 2024): 754. http://dx.doi.org/10.3390/math12050754.
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Inverse modeling can estimate uncertain parameters in subsurface reservoirs and provide reliable numerical models for reservoir development and management. The traditional simulation-based inversion method usually requires numerous numerical simulations, which is time-consuming. Recently, deep learning-based surrogate models have been widely studied as an alternative to numerical simulation, which can significantly improve the solving efficiency of inversion. However, for reservoirs with complex fracture distribution, constructing the surrogate model of numerical simulation presents a significant challenge. In this work, we present a deep graph learning-based surrogate model for inverse modeling of fractured reservoirs. Specifically, the proposed surrogate model integrates the graph attention mechanisms to extract features of fracture network in reservoirs. The graph learning can retain the discrete characteristics and structural information of the fracture network. The extracted features are subsequently integrated with a multi-layer recurrent neural network model to predict the production dynamics of wells. A surrogate-based inverse modeling workflow is then developed by combining the surrogate model with the differential evolutionary algorithm. Numerical studies performed on a synthetic naturally fractured reservoir model with multi-scale fractures illustrate the performance of the proposed methods. The results demonstrate that the proposed surrogate model exhibits promising generalization performance of production prediction. Compared with tens of thousands of numerical simulations required by the simulation-based inverse modeling method, the proposed surrogate-based method only requires 1000 to 1500 numerical simulations, and the solution efficiency can be improved by ten times.
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Tong, Kai Jun, Yan Chun Su, Li Zhen Ge, Jian Bo Chen, and Ling Ling Nie. "Numerical Simulation of the Buried Hill Reservoir in Bohai Bay." Applied Mechanics and Materials 448-453 (October 2013): 4003–8. http://dx.doi.org/10.4028/www.scientific.net/amm.448-453.4003.
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Buried hill reservoir fracture description and reservoir simulation technology have been a hot research, but also is one of the key issues that restrict the efficient development of such reservoirs. Based on JZ buried hill reservoir which heterogeneity is strong, some wells water channeling fast and difficult to control the situation for fracture affect, a typical block of dual medium reservoir numerical models which was comprehensive variety of information, discrete fracture characterization and geological modeling is established. The fractured reservoir numerical model is simulated through Eclipse software to seek the law of remaining oil distribution. Through the reservoir geological reserves and production history matching, the remaining oil distribution of main production horizon is forecasted. On this basis, the results of different oilfield development adjustment programs are predicted by numerical simulation.
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Li, Hangyu, and Louis J. Durlofsky. "Upscaling for Compositional Reservoir Simulation." SPE Journal 21, no. 03 (June 15, 2016): 0873–87. http://dx.doi.org/10.2118/173212-pa.
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Summary Compositional flow simulation, which is required for modeling enhanced-oil-recovery (EOR) operations, can be very expensive computationally, particularly when the geological model is highly resolved. It is therefore difficult to apply computational procedures that require large numbers of flow simulations, such as optimization, for EOR processes. In this paper, we develop an accurate and robust upscaling procedure for oil/gas compositional flow simulation. The method requires a global fine-scale compositional simulation, from which we compute the required upscaled parameters and functions associated with each coarse-scale interface or wellblock. These include coarse-scale transmissibilities, upscaled relative permeability functions, and so-called α-factors, which act to capture component flow rates in the oil and gas phases. Specialized near-well treatments for both injection and production wells are introduced. An iterative procedure for optimizing the α-factors is incorporated to further improve coarse-model accuracy. The upscaling methodology is applied to two example cases, a 2D model with eight components and a 3D model with four components, with flow in both cases driven by wells arranged in a five-spot pattern. Numerical results demonstrate that the global compositional upscaling procedure consistently provides very accurate coarse results for both phase and component production rates, at both the field and well level. The robustness of the compositionally upscaled models is assessed by simulating cases with time-varying well bottomhole pressures that are significantly different from those used when the coarse model was constructed. The coarse models are shown to provide accurate predictions in these tests, indicating that the upscaled model is robust with respect to well settings. This suggests that one can use upscaled models generated from our procedure to mitigate computational demands in important applications such as well-control optimization.
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Qi, Minhui, Mingzhong Li, Yanchao Li, Tiankui Guo, and Song Gao. "Numerical simulation of horizontal well network fracturing in glutenite reservoir." Oil & Gas Science and Technology – Revue d’IFP Energies nouvelles 73 (2018): 53. http://dx.doi.org/10.2516/ogst/2018051.
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Hydraulic fracturing is an economically effective technology developing the glutenite reservoirs, which have far stronger heterogeneity than the conventional sandstone reservoir. According to the field production experience of Shengli Oilfield, horizontal-well fracturing is more likely to develop a complex fractured network, which improves the stimulated volume of reservoir effectively. But the clear mechanism of horizontal-well hydraulic fracture propagation in the glutenite reservoirs is still not obtained, thus it is difficult to effectively carry out the design of fracturing plan. Based on the characteristics of the glutenite reservoirs, a coupled Flow-Stress-Damage (FSD) model of hydraulic fracture propagation is established. The numerical simulation of fracturing expansion in the horizontal well of the glutenite reservoir is conducted. It is shown that a square mesh-like fracture network is developed near the horizontal well in the reservoir with lower stress difference, in which fracture is more prone to propagate along the direction of the minimum principal stress as well. High fracturing fluids injection displacement and high fracturing fluid viscosity lead to the rise of static pressure of the fracture, which results in the rise of fracture complexity, and greater probability to deflect when encountering gravels. As the perforation density increases, the micro-fractures generated at each perforation gather together faster, and the range of the stimulated reservoir is also relatively large. For reservoirs with high gravel content, the complexity of fracture network and the effect of fracture communication are obviously increased, and the range of fracture deflection is relatively large. In the case of the same gravel distribution, the higher the tensile strength of the gravel, the greater fracture tortuosity and diversion was observed. In this paper, a simulation method of horizontal well fracture network propagation in the reservoirs is introduced, and the result provides the theoretical support for fracture network morphology prediction and plan design of hydraulic fracturing in the glutenite reservoir.
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Wu, Jun Lai, Yue Tian Liu, and Hai Ning Yang. "Parameters Optimization of Stereoscopic Horizontal Well Patterns by Using Numerical Reservoir Simulation." Advanced Materials Research 433-440 (January 2012): 2602–6. http://dx.doi.org/10.4028/www.scientific.net/amr.433-440.2602.
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Well pattern is the most important affecting factor to the ultimate recovery for an oilfield development. Many researches are reported on areal well pattern, which is widely used in conventional reservoirs development such as low permeability reservoirs, heavy oil reservoirs, multi-layer sandstone reservoirs, etc. In this paper, according to the geological characteristics of fractured buried hill reservoir of Liaohe Oilfield, we firstly present the concept of stereoscopic well patterns and compare it with common areal water flooding. By using numerical reservoir simulation method, we design and optimize the parameters of 5-spot stereoscopic horizontal well patterns, including payzone thickness and horizontal well length under different anisotropic factors of fracture permeability. This can be successfully applied on the development of MM block fractured buried hill reservoir of Liaohe Oilfield.
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Yu, Yu, Yu Bai, Yingying Ni, Yi Luo, and Shafique Junejo. "Water Quality Variation Law and Prediction Method of a Small Reservoir in China." Sustainability 14, no. 21 (October 24, 2022): 13755. http://dx.doi.org/10.3390/su142113755.
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Compared with the attention of large reservoirs, the water quality of small reservoirs also needs attention. In recent years, the problem of reservoir water quality has become increasingly serious. How to predict reservoir water quality may be an urgent problem to be solved. Taking the Yangmeiling reservoir as an example, this paper collects the hydrological and water quality data of the Yangmeiling reservoir in the last ten years, analyzes the relationship between hydrological and water quality data, and uses a machine learning method to simulate the relationship between water quality and hydrological data. The results show that the water quality of small reservoirs can be simply linked with hydrological data and can be predicted through hydrological data, and has high simulation accuracy. This method can be popularized in the simulation and prediction of the water quality of small reservoirs; it does not provide a theoretical basis for the water quality management of small reservoirs.
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Yang, Yujuin, Donald H. Burn, and Barbara J. Lence. "Development of a framework for the selection of a reservoir operating policy." Canadian Journal of Civil Engineering 19, no. 5 (October 1, 1992): 865–74. http://dx.doi.org/10.1139/l92-098.
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A methodology is developed for the selection of a preferred operating policy for a multipurpose reservoir. The methodology consists of policy identification through optimization, policy evaluation through simulation, and policy selection with a multiobjective optimization approach. The approach developed is demonstrated through an application to the Shellmouth Reservoir, a multipurpose reservoir located on the Assiniboine River in Manitoba. The operating policy identified for the Shellmouth Reservoir resulted in a satisfactory performance for the historical period of record. Key words: operating rules, reservoirs, optimization, simulation.
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Liu, Hailong, Bin Xie, Xiaozhi Xin, Haining Zhao, and Yantian Liu. "Investigation on the Extent of Retrograde Condensation of Qianshao Gas Condensate Reservoir Using PVT Experiments and Compositional Reservoir Simulation." Processes 12, no. 3 (February 29, 2024): 503. http://dx.doi.org/10.3390/pr12030503.
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In the development of the Qianshao (QS) gas condensate reservoir, it is crucial to consider the phenomenon of retrograde condensation. Understanding the condensate saturation distribution with respect to time and space within the reservoir is essential for planning and implementing effective strategies for the future development of the QS gas condensate reservoir. In this paper, various PVT experiments (including reservoir oil recombination, flash separation, constant composition expansion, and constant volume depletion) were conducted to study the PVT properties and phase behavior of QS gas condensate fluid. Based on experimental data, our in-house PVT computation package was used to determine the appropriate EOS model parameters for the QS gas condensate. A four-step reservoir fluid characterization procedure and workflow for gas condensate reservoirs was developed. Furthermore, by analyzing the pressure-temperature phase envelope, the maximum possible condensate saturation in the QS well area was estimated to be around 3%. Numerical reservoir simulation models were developed using both the EOS model and actual reservoir engineering data. These simulation models were specifically designed to replicate the retrograde condensation process that occurs during production, taking into account both vertical and horizontal wells. By simulating the production process, these single-well reservoir simulation models enable us to quantitatively evaluate the condensate saturation and its distribution over space and time within a specific control area around a single well. Reservoir simulation results show that the condensate build-up around vertical and horizontal wells is quite different. For a vertical well, the maximum condensate oil saturation (30%) around the wellbore is located approximately 5 to 6 m from the well’s center. In contrast, the horizontal well model demonstrates a maximum condensate saturation of no more than 1.5%. This information is crucial for making informed decisions regarding the effective development and management of the QS gas condensate reservoir.
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Cao, Jie, Baoyuan Yuan, and Yun Bai. "Simulation Study on Image Characteristics of Typical GPR Targets in Water Conservancy Projects." Geofluids 2021 (March 16, 2021): 1–13. http://dx.doi.org/10.1155/2021/5550620.
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With the development of the global economy, the deep leakage of reservoirs is still a serious threat to the foundation construction of key water conservancy projects such as dam foundations and bridges. Ground penetrating radar (GPR) is an effective underground imaging and detection technology. In this paper, the Groundvue series of ground penetrating radars is introduced in Britain using the 948 project fund of the Ministry of Water Resources. It is a radar with the lowest frequency in the world at present, improving detection depths and helping to ensure the reliability of a reservoir dam’s foundation. Through a large number of field tests, simulation experiments, FDTD numerical simulations, and practical engineering applications, this paper summarizes the reservoir leakage analysis method based on the Groundvue radar. The successful application at the Nanmenxia Reservoir shows that this method can effectively detect the location and path of reservoir leakage and provide technical support for the design and construction of a reservoir reinforcement project.
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Bybee, Karen. "Reservoir Simulation and Visualization: Coalbed-Methane Reservoir Simulation: An Evolving Science." Journal of Petroleum Technology 56, no. 04 (April 1, 2004): 61–63. http://dx.doi.org/10.2118/0404-0061-jpt.
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Wan, Xincheng, Lu Jin, Nicholas A. Azzolina, Shane K. Butler, Xue Yu, and Jin Zhao. "Applying Reservoir Simulation and Artificial Intelligence Algorithms to Optimize Fracture Characterization and CO2 Enhanced Oil Recovery in Unconventional Reservoirs: A Case Study in the Wolfcamp Formation." Energies 15, no. 21 (November 4, 2022): 8266. http://dx.doi.org/10.3390/en15218266.
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Reservoir simulation for unconventional reservoirs requires proper history matching (HM) to quantify the uncertainties of fracture properties and proper modeling methods to address complex fracture geometry. An integrated method, namely embedded discrete fracture model–artificial intelligence–automatic HM (EDFM–AI–AHM), was used to automatically generate HM solutions for a multistage hydraulic fracturing well in the Wolfcamp Formation. Thirteen scenarios with different combinations of matrix and fracture parameters as variables or fixed inputs were designed to generate 1300 reservoir simulations via EDFM–AI–AHM, from which 358 HM solutions were retained to reproduce production history and quantify the uncertainties of matrix and hydraulic fracture properties. The best HM solution was used for production forecasting and carbon dioxide (CO2)-enhanced oil recovery (EOR) strategy optimization. The results of the production forecast for primary recovery indicated that the drainage area for oil production was difficult to extend further into the low-permeability reservoir matrix. However, CO2 EOR simulations showed that increasing the gas injection rate during the injection cycle promoted incremental oil production from the reservoir matrix, regardless of minimum miscibility pressure. A gas injection rate of 25 million standard cubic feet per day (MMscfd) resulted in a 14% incremental oil production improvement compared to the baseline scenario with no EOR. This paper demonstrates the utility of coupling reservoir simulation with artificial intelligence algorithms to generate ensembles of simulation cases that provide insights into the relationships between fracture network properties and production.
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Clarkson, Christopher R., and J. Michael McGovern. "Optimization of CBM Reservoir Exploration and Development Strategies through Integration of Simulation and Economics." SPE Reservoir Evaluation & Engineering 8, no. 06 (December 1, 2005): 502–19. http://dx.doi.org/10.2118/88843-pa.
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Summary The unique properties and complex characteristics of coalbed methane (CBM)reservoirs, and their consequent operating strategies, call for an integrated approach to be used to explore for and develop coal plays and prospects economically. An integrated approach involves the use of sophisticated reservoir, wellbore, and facilities modeling combined with economics and decision-making criteria. A new CBM prospecting tool (CPT) was generated by combining single-well(multilayered) reservoir simulators with a gridded reservoir model, Monte Carlo(MC) simulation, and economic modules. The multilayered reservoir model is divided into pods, representing relatively uniform reservoir properties, and a" type well" is created for each pod. At every MC iteration, type-well forecasts are generated for the pods and are coupled with economic modules. A set of decision criteria contingent upon economic outcomes and reservoir characteristics is used to advance prospect exploration from the initial exploration well to the pilot and development stages. A novel approach has been used to determine the optimal well spacing should prospect development be contemplated. CPT model outcomes include a distribution of after-tax net present value (ATNPV), mean ATNPV (expected value), chance of economic success(Pe), distribution of type-well and pod gas and water production, reserves, peak gas volume, and capital. An example application of CPT to a hypothetical prospect is provided. An integrated approach also has been used to assist with production optimization of developed reservoirs. For example, an infill-well locating tool(ILT) has been constructed to provide a quick-look evaluation of infill locations in a developed reservoir. ILT, like CPT, is used for multiwell applications, combining the single-well simulator with a multilayered reservoir model and economics. An application of ILT to a CBM reservoir is provided, and the results are compared with the predictions of an Eclipse reservoir simulation. Introduction CBM reservoirs have a relatively short history of development compared to conventional reservoirs; therefore, few analog fields may be relied upon for extrapolation to new basins and new plays. Further, key reservoir properties such as absolute permeability vary greatly within and between existing developing basins, which complicates prediction of these parameters for new plays. The production performance of CBM reservoirs in new plays or basins, in which few reservoir data exist, is correspondingly difficult to predict. Existing conventional reservoir fields cannot be relied upon as analogs for CBM play analysis because coal-gas reservoirs differ from conventional reservoirs in their fluid-storage and -transport mechanisms. Coals act as source rocks and reservoirs to gas, and a significant amount of gas may be stored in the adsorbed state relative to the free-gas state. CBM reservoirs are often naturally fractured and may be modeled as dual-porosity, or even triple-porosity, reservoirs. Gas-transport mechanisms vary depending on the scale and location within the reservoir. For example, gas transport at the scale of the matrix between natural fractures is caused by the mechanism of diffusion, whereas Darcy flow occurs in the fracture system. Single- or two-phase (gas and water) flow can occur, and, hence, relative permeability characteristics are important. Permeability and gas content are two critical parameters that dictate the economic viability of CBM reservoirs. Unfortunately, there are many controls upon these parameters. For example, gas content is a function of the amount of organic matter within these rocks, the organic matter composition, organic matter thermal maturity, in-situ PT conditions, gas composition, and matrix and fracture gas-saturated porosity. Absolute permeability is dependent upon natural-fracture existence, frequency, orientation (with respect to in-situ stress), and degree of mineralization. Natural-fracture permeability is also stress- and/or desorption-dependent. Although the range of expected parameter values for a new unconventional play may be reduced by knowledge of basin hydrodynamic characteristics, tectonic regime, local and regional stratigraphy and sedimentology, local and regional structural geology, and existing production within the basin, the uncertainty associated with key reservoir variables is still likely to preclude a deterministic evaluation of reservoir producibility and recoverable reserves. Because of the variability in reservoir parameters that could be expected when exploring for CBM in existing or new basins, it is natural to use a statistically based (stochastic) approach in the prediction of gas in place, recoverable reserves, well performance, and economic return. A comprehensive study by Roadifer et al. demonstrated the use of MC simulation for screening key parameters affecting CBM production. Well performance is a key factor determining the economic viability of CBM reservoirs. Accurate prediction of well performance is required for development strategies such as optimized well spacing, completion gathering system, and wellsite design. The current work discusses how to integrate reservoir simulation and economics for the purpose of optimizing CBM exploration and development strategies. Central to the discussion is the use of single-well (multilayered)simulators, which were constructed in Excel* and incorporate many attributes of CBM reservoirs. These single-well (tank) models are discussed in the following section and have some utility for exploration and development applications when used on their own, but they are particularly powerful when integrated with reservoir, surface, and wellbore models, MC simulation,7 and economics. Two new tools (CPT and ILT) described in this work are examples of integrated tools for application to exploration and development, respectively.
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Chandra, V., P. W. M. W. M. Corbett, S. Geiger, and H. Hamdi. "Improving Reservoir Characterization and Simulation With Near-Wellbore Modeling." SPE Reservoir Evaluation & Engineering 16, no. 02 (April 3, 2013): 183–93. http://dx.doi.org/10.2118/148104-pa.
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Summary New reservoir characterization methods are needed to integrate multiscale exploration and development data, particularly at the interface between well and field models. In this paper, we illustrate a novel workflow involving high-resolution near-wellbore modeling (NWM), which allows us to accurately include seismic, wireline data, image logs, and well core logs from highly heterogeneous reservoirs in field-scale reservoir simulations. We demonstrate that an NWM-enhanced geoengineering workflow has the potential to improve reservoir characterization by applying it to a realistic clastic reservoir with high variance at small scale. We have performed a number of sensitivities comparing conventional local grid refinement (LGR) in the near-wellbore region with that involving NWM, and we obtained a significant increase in the accuracy of reservoir characterization and the calibration of dynamic models. Centimeter-scale models, containing several million cells, representing the fine geological details of the near-wellbore region, were constructed with available data from core and openhole well-log suits. The resulting well models were upscaled into regular grids with the highest resolution possible through the NWM software and incorporated into a field-scale simulation model to evaluate the dynamic behavior of the reservoir with a static-model transient test. Our results show that the use of NWM tools for reservoir modeling yields more precise flow calculations and improves our fundamental understanding of the interactions between the reservoir and the wellbore.
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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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Gutierrez, M., R. W. Lewis, and I. Masters. "Petroleum Reservoir Simulation Coupling Fluid Flow and Geomechanics." SPE Reservoir Evaluation & Engineering 4, no. 03 (June 1, 2001): 164–72. http://dx.doi.org/10.2118/72095-pa.
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Summary This paper presents a discussion of the issues related to the interaction between rock deformation and multiphase fluid flow behavior in hydrocarbon reservoirs. Pore-pressure and temperature changes resulting from production and fluid injection can induce rock deformations, which should be accounted for in reservoir modeling. Deformation can affect the permeability and pore compressibility of the reservoir rock. In turn, the pore pressures will vary owing to changes in the pore volume. This paper presents the formulation of Biot's equations for multiphase fluid flow in deformable porous media. Based on this formulation, it is argued that rock deformation and multiphase fluid flow are fully coupled processes that should be accounted for simultaneously, and can only be decoupled for predefined simple loading conditions. In general, it is shown that reservoir simulators neglect or simplify important geomechanical aspects that can impact reservoir productivity. This is attributed to the fact that the only rock mechanical parameter involved in reservoir simulations is pore compressibility. This parameter is shown to be insufficient in representing aspects of rock behavior such as stress-path dependency and dilatancy, which require a full tensorial constitutive relation. Furthermore, the pore-pressure changes caused by the applied loads from nonpay rock and the influence of nonpay rock on reservoir deformability cannot be accounted for simply by adjusting the pore compressibility. Introduction In the last two decades, there has been a strong emphasis on the importance of geomechanics in several petroleum engineering activities such as drilling, borehole stability, hydraulic fracturing, and production-induced compaction and subsidence. In these areas, in-situ stresses and rock deformations, in addition to fluid-flow behavior, are key parameters. The interaction between geomechanics and multiphase fluid flow is widely recognized in hydraulic fracturing. For instance, Advani et al.1 and Settari et al.2 have shown the importance of fracture-induced in-situ stress changes and deformations on reservoir behavior and how hydraulic fracturing can be coupled with reservoir simulators. However, in other applications, geomechanics, if not entirely neglected, is still treated as a separate aspect from multiphase fluid flow. By treating the two fields as separate issues, the tendency for each field is to simplify and make approximate assumptions for the other field. This is expected because of the complexity of treating geomechanics and multiphase fluid flow as coupled processes. Recently, there has been a growing interest in the importance of geomechanics in reservoir simulation, particularly in the case of heavy oil or bituminous sand reservoirs,3,4 water injection in fractured and heterogeneous reservoirs,5–7 and compacting and subsiding fields.8,9 Several approaches have been proposed to implement geomechanical effects into reservoir simulation. The approaches differ on the elements of geomechanics that should be implemented and the degree to which these elements are coupled to multiphase fluid flow. The objective of this paper is to illustrate the importance of geomechanics on multiphase flow behavior in hydrocarbon reservoirs. An extension of Biot's theory10 for 3D consolidation in porous media to multiphase fluids, which was proposed by Lewis and Sukirman,11 will be reviewed and used to clarify the issues involved in coupling fluid flow and rock deformation in reservoir simulators. It will be shown that for reservoirs with relatively deformable rock, fluid flow and reservoir deformation are fully coupled processes, and that such coupled behaviors cannot be represented sufficiently by a pore-compressibility parameter alone, as is done in reservoir simulators. The finite-element implementation of the fully coupled equations and the application of the finite-element models to an example problem are presented to illustrate the importance of coupling rock deformation and fluid flow. Multiphase Fluid Flow in Deformable Porous Media Fig. 1 illustrates the main parameters involved in the flow of multiphase fluids in deformable porous media and how these parameters ideally interact. The main quantities required to predict fluid movement and productivity in a reservoir are the fluid pressures (and temperatures, in case of nonisothermal problems). Fluid pressures also partly carry the loads, which are transmitted by the surrounding rock (particularly the overburden) to the reservoir. A change in fluid pressure will change the effective stresses following Terzaghi's12 effective stress principle and cause the reservoir rock to deform (additional deformations are induced by temperature changes in nonisothermal problems). These interactions suggest two types of fluid flow and rock deformation coupling:Stress-permeability coupling, where the changes in pore structure caused by rock deformation affect permeability and fluid flow.Deformation-fluid pressure coupling, where the rock deformation affects fluid pressure and vice versa. The nature of these couplings, specifically the second type, are discussed in detail in the next section. Stress-Permeability Coupling This type of coupling is one where stress changes modify the pore structure and the permeability of the reservoir rock. A common approach is to assume that the permeability is dependent on porosity, as in the Carman-Kozeny relation commonly used in basin simulators. Because porosity is dependent on effective stresses, permeability is effectively stress-dependent. Another important effect, in addition to the change in the magnitude of permeability, is on the change in directionality of fluid flow. This is the case for rocks with anisotropic permeabilities, where the full permeability tensor can be modified by the deformation of the rock. Examples of stress-dependent reservoir modeling are given by Koutsabeloulis et al.6 and Gutierrez and Makurat.7 In both examples, the main aim of the coupling is to account for the effects of in-situ stress changes on fractured reservoir rock permeability, which in turn affect the fluid pressures and the stress field. The motivation for the model comes from the field studies done by Heffer et al.5 showing that there is a strong correlation between the orientation of the principal in-situ stresses with the directionality of flow in fractured reservoirs during water injection. There is also growing evidence that the earth's crust is generally in a metastable state, where most faults and fractures are critically stressed and are on the verge of further slip.13 This situation will broaden the range of cases with strong potential for coupling of fluid flow and deformation.
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Jiang, Yanjiao, Jian Zhou, Xiaofei Fu, Likai Cui, Chao Fang, and Jiangman Cui. "Analyzing the Origin of Low Resistivity in Gas-Bearing Tight Sandstone Reservoir." Geofluids 2021 (August 30, 2021): 1–15. http://dx.doi.org/10.1155/2021/4341804.
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Complex characteristics exist in the resistivity response of Gs reservoirs in the central inversion belt of the Xihu Sag, East China Sea Basin. Some drilling wells have confirmed the existence of abnormally low resistivity in gas reservoirs of the area; and the electrical logging response was unable to reflect fluid properties of the reservoir accurately. Therefore, it is necessary to analyze the origin of the low resistivity and determine its controlling factors. Based on experimental data of core analysis and numerical simulations of mud invasion, this study thoroughly explores the origin of low resistivity in the subject gas-bearing reservoir considering both internal and external factors. The results indicated that when there is no or a low degree of mud invasion, the fine lithology, complex pore structure, additional clay mineral conductivity, and high content of pyrite are the main internal factors driving the conditions present in the studied gas reservoir. When mud invasion occurs, the invasion of highly saline mud is the main external cause of low resistivity. The numerical simulation results indicated that a formation with good permeability and high overbalance pressure has a deep invasion depth. The resistivity around the well is obviously reduced after the invasion, and low resistivity would form easily. Combined with actual data of several wells, the main influencing factors of the reservoir’s electrical characteristics were analyzed, and the main controlling factors of low resistivity in the gas reservoirs are given. This study provides valuable support for studying the low-contrast complex reservoir conductivity mechanism. The study also offers novel ideas for accurate calculation of saturation and the meticulous evaluation of reservoir for subsequent studies.
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Fenicia, F., H. H. G. Savenije, P. Matgen, and L. Pfister. "Is the groundwater reservoir linear? Learning from data in hydrological modelling." Hydrology and Earth System Sciences Discussions 2, no. 4 (August 30, 2005): 1717–55. http://dx.doi.org/10.5194/hessd-2-1717-2005.
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Abstract. Although catchment behaviour during recession periods appears to be better identifiable than in other periods, the representation of hydrograph recession is often weak in hydrological simulations. Reason lies in the various sources of uncertainty that affect hydrological simulations, and in particular in the inherent uncertainty concerning model conceptualizations, when they are based on an a-priori representation of the natural system. When flawed conceptualizations combine with calibration strategies that favour an accurate representation of peak flows, model structural inadequacies manifest themselves in a biased representation of other aspects of the simulation, such as flow recession and low flows. In this paper we try to reach good model performance in low flow simulation and make use of a flexible model structure that can adapt to match the observed discharge behaviour during recession periods. Moreover, we adopt a step-wise calibration procedure where we try to avoid that the simulation of low flows is neglected in favour of other hydrograph characteristics. The model used is designed to reproduce specific hydrograph characteristics and is composed of four reservoirs: an interception reservoir, an unsaturated soil reservoir, a fast reacting reservoir, and a slow reacting reservoir. The slow reacting reservoir conceptualises the processes that lead to the generation of the slow hydrograph component, and is characterized by a storage-discharge relation that is not determined a-priori, but is derived from the observations following a ``top-down'' approach. The procedure used to determine this relation starts by calculating a synthetic master recession curve that represents the long-term recession of the catchment. Next, a calibration procedure follows to force the outflow from the slow reacting reservoir to match the master recession curve. Low flows and high flows related parameters are calibrated in separate stages because we consider them to be related to different processes, which can be identified separately. This way we avoid that the simulation of low discharges is neglected in favour of a higher performance in simulating peak discharges. We have applied this analysis to several catchments in Luxembourg, and in each case we have determined which form (linear or non linear) of the storage-discharge relationship best describes the slow reacting reservoir. We conclude that in all catchments except one (where human interference is high) a linear relation applies.
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Ghassemzadeh, Shahdad, Maria Gonzalez Perdomo, Manouchehr Haghighi, and Ehsan Abbasnejad. "A data-driven reservoir simulation for natural gas reservoirs." Neural Computing and Applications 33, no. 18 (March 16, 2021): 11777–98. http://dx.doi.org/10.1007/s00521-021-05886-y.
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