Journal articles: 'Thermal reservoir simulation'

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Zaydullin, Rustem, Denis V. Voskov, Scott C. James, Heath Henley, and Angelo Lucia. "Fully compositional and thermal reservoir simulation." Computers & Chemical Engineering 63 (April 2014): 51–65. http://dx.doi.org/10.1016/j.compchemeng.2013.12.008.

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Winterfeld, P. H., and Yu-Shu Wu. "Simulation of Coupled Thermal/Hydrological/Mechanical Phenomena in Porous Media." SPE Journal 21, no. 03 (June 15, 2016): 1041–49. http://dx.doi.org/10.2118/173210-pa.

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Summary For processes such as production from low-permeability reservoirs and storage in subsurface formations, reservoir flow and the reservoir stress field are coupled and affect one another. This paper presents a thermal/hydrological/mechanical (THM) reservoir simulator that is applicable to modeling such processes. The fluid- and heat-flow portion of our simulator is for general multiphase, multicomponent, multiporosity systems. The geomechanical portion consists of an equation for mean stress, derived from linear elastic theory for a thermo-poroelastic system, and equations for stress-tensor components that depend on mean stress and other variables. The integral finite-difference method is used to solve these equations. The mean-stress and reservoir-flow variables are solved implicitly, and the remaining stress-tensor components are solved explicitly. Our simulator is verified by use of analytical solutions for stress- and strain-tensor components and is compared with published results.

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Swinkels, Wim J. A. M., and Rik J. J. Drenth. "Thermal Reservoir Simulation Model of Production From Naturally Occurring Gas Hydrate Accumulations." SPE Reservoir Evaluation & Engineering 3, no. 06 (December 1, 2000): 559–66. http://dx.doi.org/10.2118/68213-pa.

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Summary Reservoir behavior of a hydrate-capped gas reservoir is modeled using a three-dimensional thermal reservoir simulator. The model incorporates a description of the phase behavior of the hydrates, heat flow and compaction in the reservoir and the hydrate cap. The model allows the calculation of well productivity, evaluation of well configurations and matching of experimental data. It shows the potentially self-sealing nature of the hydrate cap. Production scenarios were also investigated for production from the solid hydrate cap using horizontal wells and various ways of dissociating the gas hydrates. These investigations show the role of excessive water production and the requirement for water handling facilities. A data acquisition program is needed to obtain reservoir parameters for gas hydrate accumulations. Such parameters include relative phase permeability, heat capacity and thermal conductivity of the hydrate-filled formations, compaction parameters and rate of hydrate formation and decomposition in the reservoir. Introduction Interest in natural gas hydrates is increasing with foreseen requirements in the next century for large volumes of natural gas as a relatively clean hydrocarbon fuel and with increasing exploration and production operation experience in deepwater and Arctic drilling. While progress is being made in identifying and drilling natural gas hydrates, there is also the need to look ahead and develop production concepts for the potentially large deposits of natural gas hydrates and hydrate-capped gas reservoirs. We are now reaching the stage in which some of the simplifying assumptions of analytical models are not sufficient any longer for developing production concepts for natural gas hydrate accumulations. For this reason we have investigated the option of applying a conventional industrial thermal reservoir simulator to model production from natural gas hydrates. Reservoir behavior of free gas trapped under a hydrate seal is to a great extent similar to the behavior of a conventional gas field with the following major differences:thermal effects on the overlying hydrate cap have to be taken into account;potentially large water saturations can build up in the reservoir;relatively low pressures;high formation compressibility can be expected. Use of a thermal compositional reservoir simulator to model the behavior of hydrates and hydrate-capped gas has not been attempted before. We have shown before1 that existing knowledge of phase behavior and thermal reservoir modeling can be fruitfully combined to better understand the behavior of natural gas hydrates in the subsurface. In this paper we will expand on this work and provide further results. After an overview of the model setup, we will first show some results for modeling the depletion of the gas accumulations underlying the hydrate layer. This will be followed by the results for production from the hydrate layer itself, applying heat injection in the formation. Modeling Natural Hydrate Associated Production Attempts to model the behavior of hydrate-capped gas and hydrate reservoirs have been documented by various authors in the literature. Simple energy balance approaches are used by Kuuskraa and Hammershaimb et al.2 Masuda et al.,3 Yousif et al.,4 and Xu and Ruppel5 have presented numerical solutions to analytical models. The first two of these papers do not include thermal effects in their calculations. Reference 5 is specifically aimed at the formation phase of hydrates in the reservoir over geological times, and is less relevant to the production phase. An attempt at explaining the production behavior of a possibly hydrate-capped gas accumulation is described by Collett and Ginsburg.6 The depth and thickness of the hydrate layer under various conditions were described by Holder et al.7 and by Hyndman et al.8 All these approaches apply analytical methods to explain the subsurface occurrence and behavior of natural gas hydrates using various simplifying assumptions. In earlier work1 we have shown that modeling the reservoir behavior of hydrate-capped gas reservoirs with a three-dimensional (3D) thermal hydrocarbon reservoir simulator allows us to account for reservoir aspects, which are disregarded in most analytical models. Such aspects includewell inflow pressure drop and the effects of horizontal and vertical wells in the reservoir;heat transfer between the reservoir fluids and the formation;the geothermal gradient;phase behavior and pressure/volume/temperature (PVT) properties of the reservoir fluids as a fluction of pressure decline;internal architecture and geometry of the reservoir; andreservoir compaction effects. Objective The current study was undertaken to show the feasibility of modeling production behavior of a hydrate-capped gas reservoir in a conventional 3D thermal reservoir simulation model. Objectives of the modeling work include the following.Understand reservoir behavior of natural gas hydrates and hydrate-capped reservoirs. Important aspects of the reservoir thermodynamics are the potential self-preservation capacity of the hydrate cap, the limitation on hydrate decomposition imposed by the thermal conductivity of the rock and the influence of compaction.Confirm material and energy balance analytical calculations.Investigate production options, such as the application of horizontal wells.Calculate well productivity and evaluate well configurations. This study was performed as part of an ongoing project involving other geological and petroleum engineering disciplines. Accounting for Thermal Effects In this study the thermal version of an in-house hydrocarbon reservoir simulator is used.9 We represent the reservoir fluids by a gaseous, a hydrate and an aqueous phase, which are made up of three components, two hydrocarbons and a water component.

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Liu, Hui, Zhangxin Chen, Lihua Shen, Xiaohu Guo, and Dongqi Ji. "Well modelling methods in thermal reservoir simulation." Oil & Gas Science and Technology – Revue d’IFP Energies nouvelles 75 (2020): 63. http://dx.doi.org/10.2516/ogst/2020058.

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Reservoir simulation is of interdisciplinary research, including petroleum engineering, mathematics, and computer sciences. It studies multi-phase (water, oil and gas) flow in porous media and well modelling. The latter describes well behavior using physical and mathematical methods. In real world applications, there are many types of wells, such as injection wells, production wells and heaters, and their various operations, such as pressure control, rate control and energy control. This paper presents commonly used well types, well operations, and their mathematical models, such as bottom hole pressure, water rate, oil rate, liquid rate, subcool, and steam control. These are the most widely applied models in thermal reservoir simulations, and some of them can even be applied to the black oil and compositional models. The purpose of this paper is to review these well modelling methods and their mathematical models, which explain how the well operations are defined and computed. We believe a detailed introduction is important to other reseachers and simulator developers. They have been implemented in our in-house parallel thermal simulator. Numerical experiments have been carried out to validate the model implementations and demonstrate the scalability of the parallel thermal simulator.

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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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Yashin, A., I. Indrupskiy, and O. Lobanova. "Simulation of composition changes in reservoirs with large hydrocarbon columns and temperature gradient." Georesursy 20, no. 4 (November 30, 2018): 336–43. http://dx.doi.org/10.18599/grs.2018.4.336-343.

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This paper compares three methods for calculation of initial composition variation with depth in hydrocarbon reservoirs: considering thermal diffusion, considering temperature gradient without thermal diffusion effects; and by gravity forces only. Newton method-based numerical algorithm was implemented for solution of thermodynamic equations to evaluate pressure and hydrocarbon composition. Test calculations are performed for main gas-condensate reservoir of Vuktylskoye field with a gas column of 1350 m. The results obtained with the numerical algorithm indicate that gravity segregation impact is the strongest for all the cases considered. Concentration decreases with depth for low molecular weight components and increases for high molecular weight components. The higher molecular weight of the component, the stronger variation of its concentration with depth. Initial reservoir pressure also changes accordingly. However, thermal diffusion also has a significant influence on variation of hydrocarbon composition with depth and initial reservoir pressure. For the test case considered, thermal diffusion magnifies the impact of gravity and results in strongly nonlinear dependencies of component concentrations on depth. When thermal gradient is taken into account without thermal diffusion effects, the results are only slightly different from those with the isothermal gravity segregation calculations. None of the calculation methods were successful in matching estimates of initial composition variation with depth obtained from well exploitation data. Physical mechanisms governing variation of composition within the main reservoir of the Vuktylskoye field require additional investigation. Despite the long history of the reservoir development, this problem was previously studied based only on field development data.

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Jansen, Gunnar, and Stephen A. Miller. "On the Role of Thermal Stresses during Hydraulic Stimulation of Geothermal Reservoirs." Geofluids 2017 (2017): 1–15. http://dx.doi.org/10.1155/2017/4653278.

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Massive quantities of fluid are injected into the subsurface during the creation of an engineered geothermal system (EGS) to induce shear fracture for enhanced reservoir permeability. In this numerical thermoelasticity study, we analyze the effect of cold fluid injection on the reservoir and the resulting thermal stress change on potential shear failure in the reservoir. We developed an efficient methodology for the coupled simulation of fluid flow, heat transport, and thermoelastic stress changes in a fractured reservoir. We performed a series of numerical experiments to investigate the effects of fracture and matrix permeability and fracture orientation on thermal stress changes and failure potential. Finally, we analyzed thermal stress propagation in a hypothetical reservoir for the spatial and temporal evolution of possible thermohydraulic induced shear failure. We observe a strong influence of the hydraulic reservoir properties on thermal stress propagation. Further, we find that thermal stress change can lead to induced shear failure on nonoptimally oriented fractures. Our results suggest that thermal stress changes should be taken into account in all models for long-term fluid injections in fractured reservoirs.

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Yu, Xinan, Xiaoping Li, Shuoliang Wang, and Yi Luo. "A Multicomponent Thermal Fluid Numerical Simulation Method considering Formation Damage." Geofluids 2021 (January 14, 2021): 1–15. http://dx.doi.org/10.1155/2021/8845896.

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Multicomponent thermal fluid huff and puff is an innovative heavy oil development technology for heavy oil reservoirs, which has been widely used in offshore oilfields in China and has proved to be a promising method for enhancing oil recovery. Components of multicomponent thermal fluids contain many components, including carbon dioxide, nitrogen, and steam. Under high temperature and high pressure conditions, the complex physical and chemical reactions between multicomponent thermal fluids and reservoir rocks occur, which damage the pore structure and permeability of core. In this paper, the authors set up a reservoir damage experimental device, tested the formation permeability before and after the injection of multiple-component thermal fluids, and obtained the formation damage model. The multicomponent thermal fluid formation damage model is embedded in the component control equation, the finite difference method is used to discretize the control equation, and a new multielement thermal fluid numerical simulator is established. The physical simulation experiment of multicomponent thermal fluid huff and puff is carried out by using the actual sand-packed model. By comparing the experimental results with the numerical simulation results, it is proved that the new numerical simulation model considering formation damage proposed in this paper is accurate and reliable.

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Sabeti, R., S. Jamali, and H. H. Jamali. "Simulation of Thermal Stratification and Salinity Using the Ce-Qual-W2 Model (Case Study: Mamloo Dam)." Engineering, Technology & Applied Science Research 7, no. 3 (June 12, 2017): 1664–69. http://dx.doi.org/10.48084/etasr.1062.

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Due to the shortage of fresh water, the quality of stored water in reservoirs has become increasingly important. Thermal regime and salinity are factors that affect the quality of water reservoirs. These two parameters were studied in Mamloo Dam in Tehran province. This dam has recently started to be uses as a source of drinking water for Tehran and thus its water quality is of increased importance. In this regard, the hydrodynamic model for 2014 to 2015 was built and calibrated by the CE-QUAL-W2 model and the model was used to simulate the thermal regime and salinity up to 2020. Two main scenarios were studied in this period, the continuation of the current situation or a 2.5% increase in water requirements and 5% decrease in discharge. The results show that the reservoir will experience thermal stratification in the summer and vertical mixing in the winter. Dased on these results Mamloo reservoir is in branch of warm Monomictic lake. Also results showed that thermal stratification and ssalinity stratification dominates simultaneity. Besides this issue with 2.5% increase in water requirements and 5% decrease in discharge, duration of summer thermal stratification will decrease although intensity of thermal stratification will increase.

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Dong, Xiao Hu, Hui Qing Liu, Zhan Xi Pang, and Yong Gang Yi. "Variation Characteristics of Reservoir Physical Properties after Thermal Recovery in Heavy Oil Reservoirs." Advanced Materials Research 550-553 (July 2012): 2848–52. http://dx.doi.org/10.4028/www.scientific.net/amr.550-553.2848.

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With the development of heavy oil reservoirs, it faced a series of problems. Using the theory of thermal-hydrological-mechanical (THM) coupling, a predictive model of reservoir physical properties (RPP) after thermal recovery is established. Based on this model, the changing process of reservoir physical properties is simulated by the method of numerical simulation. The obtained results show that the sand production has a significant influence on RPP. By contrast with rock deformation, it has a smaller influence on RPP. The influence caused by the former is about 5~8 times than latter. During the period of steam injection, resulting from the movement of sand grain and expansion of reservoir, both porosity and permeability of reservoir are on the rise. Due to the sand production and reservoir compression, a reducing tendency is happened in the production period. The changes of RPP in reservoir are huge along the main streamline direction, and it might change because of the presence of high-permeability path.

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Lee, Kyung Jae, George J. Moridis, and Christine A. Ehlig-Economides. "Compositional simulation of hydrocarbon recovery from oil shale reservoirs with diverse initial saturations of fluid phases by various thermal processes." Energy Exploration & Exploitation 35, no. 2 (December 22, 2016): 172–93. http://dx.doi.org/10.1177/0144598716684307.

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We have studied the hydrocarbon production from oil shale reservoirs filled with diverse initial saturations of fluid phases by implementing numerical simulations of various thermal in-situ upgrading processes. We use our in-house fully functional, fully implicit, and non-isothermal simulator, which describes the in-situ upgrading processes and hydrocarbon recovery by multiphase-multicomponent systems. We have conducted two sets of simulation cases—five-spot well pattern problems and Shell In-situ Conversion Process (ICP) problems. In the five-spot well pattern problems, we have analyzed the effects of initial fluid phase that fills the single-phase reservoir and thermal processes by four cases—electrical heating in the single-phase-aqueous reservoir, electrical heating in the single-phase-gaseous reservoir, hot water injection in the single-phase-aqueous reservoir, and hot CO2 injection in the single-phase-gaseous reservoir. In the ICP problems, we have analyzed the effects of initial saturations of fluid phases that fill two-phase-aqueous-and-gaseous reservoir by three cases—initial aqueous phase saturations of 0.16, 0.44, and 0.72. Through the simulation cases, system response and production behavior including temperature profile, kerogen fraction profile, evolution of effective porosity and absolute permeability, phase production, and product selectivity are analyzed. In the five-spot well pattern problems, it is found that the hot water injection in the aqueous phase reservoir shows the highest total hydrocarbon production, but also shows the highest water-oil-mass-ratio. Productions of phases and components show very different behavior in the cases of electrical heating in the aqueous phase reservoir and the gaseous phase reservoir. In the ICP problems, it is found that the speed of kerogen decomposition is almost identical in the cases, but the production behavior of phases and components is very different. It is found that more liquid organic phase has been produced in the case with the higher initial saturation of aqueous phase by the less production of gaseous phase.

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Leskiw, Christopher, and Ian D. Gates. "Monitoring of SAGD Steam-Chamber Conformance by Using White-Noise-Reflection Processes." SPE Journal 17, no. 04 (November 27, 2012): 1246–54. http://dx.doi.org/10.2118/137750-pa.

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Summary Thermal stimulation of bitumen in oil-sands reservoirs is a critical requirement for the success of steam-based recovery processes such as steam-assisted gravity drainage (SAGD). If the bitumen is not heated, it remains at its original viscosity, often in the millions of centipoise and, thus, is not mobilized so that it cannot be moved to a production well. All oil-sands reservoirs are heterogeneous, both with respect to geology and fluid composition, and, thus, conformance of steam in the reservoir is not uniform. At present, real-time monitoring of the steam-conformance zone in the reservoir is not possible, and, thus, the spatial distribution of heat delivery to the reservoir is uncertain. In this research, a new method for detecting heterogeneity and monitoring steam chambers has been developed and tested by detailed thermal/acoustic reservoir simulation. Here, a thermal fluid-flow simulator was one-way coupled to a wave-propagation simulator (information passed is density alone) to evaluate the potential of identifying rock and fluid discontinuities during a SAGD operation with coded white-noise-reflection processes. Digital communication systems use coded white-noise processes to make advantageous use of unexpected reflections from environmental heterogeneities. The proposed theory and subsequent simulations reveal that it is possible to resolve the edge of the SAGD steam chamber and to image the heterogeneity within the reservoir as it evolves with white-noise-reflection methods. The properties of the signals described provide an opportunity for property detection at lower power levels and higher frequencies than traditional seismic methods. Furthermore, the signals are such that the noise from recovery processes and the native reservoir environment do not interfere with the detection methods, allowing for the monitoring method to be used concurrently with the recovery process.

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Wang, Yibo, Lijuan Wang, Yang Bai, Zhuting Wang, Jie Hu, Di Hu, Yaqi Wang, and Shengbiao Hu. "Assessment of Geothermal Resources in the North Jiangsu Basin, East China, Using Monte Carlo Simulation." Energies 14, no. 2 (January 6, 2021): 259. http://dx.doi.org/10.3390/en14020259.

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Geothermal energy has been recognized as an important clean renewable energy. Accurate assessment of geothermal resources is an essential foundation for their development and utilization. The North Jiangsu Basin (NJB), located in the Lower Yangtze Craton, is shaped like a wedge block of an ancient plate boundary and large-scale carbonate thermal reservoirs are developed in the deep NJB. Moreover, the NJB exhibits a high heat flow background because of its extensive extension since the Late Mesozoic. In this study, we used the Monte Carlo method to evaluate the geothermal resources of the main reservoir shallower than 10 km in the NJB. Compared with the volumetric method, the Monte Carlo method takes into account the variation mode and uncertainties of the input parameters. The simulation results show that the geothermal resources of the sandstone thermal reservoir in the shallow NJB are very rich, with capacities of (6.6–12) × 1020 J (mean 8.6 × 1020 J), (5.1–16) × 1020 J (mean 9.1 × 1020 J), and (3.2–11) × 1020 J (mean 6.6 × 1020 J) for the Yancheng, Sanduo and Dai’nan sandstone reservoir, respectively. In addition, the capacity of the geothermal resource of the carbonate thermal reservoir in the deep NJB is far greater than the former, reaching (9.9–15) × 1021 J (mean 12 × 1021 J). The results indicate capacities of a range value of (1.2–1.7) × 1021 J (mean 1.4 × 1022 J) for the whole NJB (<10 km).

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Franco, Alessandro, and Maurizio Vaccaro. "Sustainable Sizing of Geothermal Power Plants: Appropriate Potential Assessment Methods." Sustainability 12, no. 9 (May 8, 2020): 3844. http://dx.doi.org/10.3390/su12093844.

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The paper analyzes the problem of defining the potential of geothermal reservoirs and the definition of a sustainable size of a geothermal power plant in the preliminary design phase. While defining the size of a geothermal plant, the objective is to find a compromise between renewability, technical sustainability, and economic return-related issues. In the first part of the paper the simplified lumped parameter approach based on the First-Order methods and their further evolutions and limitations is proposed. Experimental data available for some geothermal reservoirs are used for critical analysis of the simplified approaches for estimating the renewability and sustainability of the production of geothermal plants. In the second part the authors analyze methods based on theoretical heat transfer analysis supported by experimental data acquired from the geothermal field (thermal properties of the rock, porosity of the reservoir, and natural heat flux) and finally consider the numerical simulation as a method to connect the two approaches discussed before. The sustainability of geothermal power production can be estimated taking into account the energy stored in the reservoir and the thermal and fluid dynamic analysis of the reservoir. From this perspective, the numerical simulation of the reservoir can be considered as an effective method for the estimation of a sustainable mass flow rate extraction. Some specific cases are analyzed and discussed.

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Alpak, Faruk O. "Robust Fully-Implicit Coupled Multiphase-Flow and Geomechanics Simulation." SPE Journal 20, no. 06 (December 18, 2015): 1366–83. http://dx.doi.org/10.2118/172991-pa.

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Summary Material nonlinearity, boundary and arching constraints, nonuniform reservoir flows, sliding along material interfaces, or faults are among the causes of shear deformation or changes in the total stresses and the resulting stress redistribution in hydrocarbon reservoirs. Previous studies have demonstrated that shear or nonuniform deformation and stress redistribution in subsurface formations may have significant effects on reservoir fluid flows. Thus, a two-way coupled analysis is the required approach under circumstances where the shear deformation or changes in total stresses in the reservoir cannot be neglected. A coupled multiphysics simulator is developed for the dynamic modeling of multiphase thermal/compositional flow, and poroelastoplastic geomechanical deformation. The equations that govern multiphase flow in permeable media, heat transport, and poroelastoplastic geomechanics together lead to a highly nonlinear system. Finite-volume and Galerkin finite-element methods are used for the numerical solution of thermal/compositional multiphase fluid-flow and geomechanics equations on general hexahedral grids, respectively. Because of its improved stability and rapid convergence characteristics, the resulting multiphysics system of equations is solved with a fully-implicit formulation by use of an effective implementation of the Newton-Raphson method in the default mode. The coupled simulator is by design maximally modular with self-contained flow and geomechanics modules that can be operated in a two-way coupled mode with explicit-, iterative-, and fully-implicit-coupling options. The coupled-modeling system lends itself naturally not only to near-wellbore coupled flow and geomechanical deformation problems where poroplasticity may play a more prominent role, but also to reservoir-scale simulations where both poroelasticity and poroplasticity are relevant. The coupled simulator is validated against analytical solutions for simple cases, by use of published data in the open literature. Validation results demonstrate the robust, fast, and accurate predictive capabilities of the multiphysics modeling protocol.

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Shourian, Mojtaba, Ali Moridi, and Mohammad Kaveh. "Modeling of eutrophication and strategies for improvement of water quality in reservoirs." Water Science and Technology 74, no. 6 (June 27, 2016): 1376–85. http://dx.doi.org/10.2166/wst.2016.322.

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The purpose of this study is to survey the thermal regime and eutrophication states in Ilam reservoir in Iran as the case study. For this purpose and to find solutions for improving the water's quality in the reservoir, two general strategies for reducing the entering pollution loads and water depletions from the reservoir's outlets were analyzed by use of the CE-QUAL-W2 model. Results of the simulation of the present situation show the existence of thermal stratification during summer, which results in the qualitative stratification in the reservoir. According to the qualitative criteria, the Ilam reservoir's state is between mesotrophic and eutrophic. Results of the scenarios of reduction of the nutrients show that in the scenario of 50% reduction of the phosphorus and nitrogen loads into the reservoir, the state of the reservoir would recover from eutrophic to semi-eutrophic. Also, release of water from the reservoir during September, October and November would cause the restoration of the quality of water in the reservoir. To avoid the occurrence of critical eutrophication in the reservoir, reducing the ponding time in the reservoir by fast depletion, preventing entrance of the upstream villages' sewage and agricultural drained waters, which are sources of nitrate and phosphate contamination into the rivers, and also management of the usage of agricultural fertilizers have been suggested.

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Kavouri, K., A. Arvanitis, C. Athanassoulis, and M. Xenakis. "SIMULATION OF THE GEOTHERMAL RESERVOIR OF THERMA - NIGRITA, CENTRAL MACEDONIA, GREECE." Bulletin of the Geological Society of Greece 50, no. 2 (July 27, 2017): 740. http://dx.doi.org/10.12681/bgsg.11780.

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The geothermal field of Therma - Nigrita is among the most important low enthalpy fields in Greece. It is located at the SW part of the Strymon basin (Central Macedonia). The geothermal research at Nigrita was launched by IGME during 1980- 1982. Actually, it is exploited mainly for agricultural use and thermal spa. The geothermal field of Therma - Nigrita, officially characterized by Ministerial Decision, covers an area of 10 km², has a pressurized reservoir at 70-500 m depth, showing temperatures of 40-64°C and geothermal fluids containing large amounts of CO2. In this paper the development of a 3D model for the reservoir of Therma - Nigrita, is presented. For this purpose the FEFLOW code is employed which simulates fluid flow and heat transfer in the geothermal reservoir under transient state conditions. Following, three different management scenarios are tested for a ten-year period. The first scenario examines the evolution of the reservoir under no-exploitation conditions, the second one represents the current exploitation scheme and in the third scenario the production rates are doubled. According to the simulation results, the decrease in temperature is not expected greater than 1% for all scenarios, while the effect on hydraulic heads is significant for both scenarios 2 and 3.

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Bogdanov, I. I. "Simulation of the thermal recovery process in a layered reservoir." Fluid Dynamics 29, no. 3 (May 1994): 396–401. http://dx.doi.org/10.1007/bf02230775.

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Escobar, Freddy Humberto, Angela Patricia Zambrano, Diana Vanessa Giraldo, and José Humberto Cantillo. "Pressure and pressure derivative analysis without type-curve matching for thermal recovery processes." CT&F - Ciencia, Tecnología y Futuro 4, no. 4 (December 1, 2011): 23–35. http://dx.doi.org/10.29047/01225383.226.

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In recent years, a constant increase of oil prices and declining reserves of coventional crude oils have produced those deposits of lights to be considered economically unattractive to be produced as an alternative way to keep the world´s oil supply volume. Heavy oil deposits are mainly characterized by having high resistance to flow (high viscosity), which makes them diffi-cult to produce. Since oil viscosity is a property that is reduced by increasing the temperature, thermal recovery techniques -such as steam injection or in-situ combustion- have become over the years the main tool for tertiary recovery of these oils. Composite reservoirs can occur naturally or may be artificially created. Changes in reservoir width, facies or type of fluid (hydraulic contact) forming two different regions are examples of two-zone composite reservoirs occurring naturally. On the other hand, such enhanced oil recovery projects as waterflooding, polymer floods, gas injection, in-situ combustion, steam drive, and CO2 miscible artificially create conditions where the reservoir can be considered as a composite system. A reservoir undergoing a thermal recovery process is typically idealized as a two-zone composite reservoir, in which, the inner region represents the swept region surrounding the injection well and the outer region represents the larger portion of the reservoir. Additionally, there is a great contrast between the mobilities of the two zones and the storativity ratio being different to one. In this work, the models and techniques developed and implemented by other authors have been enhanced. Therefore, the interpretations of the well tests can be done in an easier way, without using type-curve matching. A methodology which utilizes a pressure and pressure derivative plot is developed for reservoirs subjected to thermal recovery so that mobilities, storativity ratio, distance to the radial discontinuity or thermal front and the drainage area can be estimated. The precedence of the heat source (in-situ combustion or hot injected fluids) does not really matter for the application of this methodology; however, this was successfully verified by its application to synthetic and field examples of in-situ combustion. The point of comparison was the input data used for simulation for the synthetic case and the results from simulation matching and from previous studies for the field cases.

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Zhou, Yanxia, Xiangguo Lu, Bao Cao, Yigang Liu, Yunbao Zhang, and Xun Zhong. "Recovery Method and Parameter Optimization of a Pilot Test for Conformance Control Flooding and Thermal Recovery in the Offshore Heavy Oilfield." Geofluids 2021 (January 13, 2021): 1–14. http://dx.doi.org/10.1155/2021/6660468.

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NB35-2 oilfield is a typical offshore sandstone reservoir with viscous crude oil and high permeability. Due to the inherent severe heterogeneity, the efficiency of conventional water flooding is pretty low and usually accompanied with early water breakthrough. In order to recover the residual oil and better realize its potential, applications of enhanced oil recovery (EOR) technology are necessary. However, the selection of EOR method and related parameters may directly impact the final results and can be noticeably different for different reservoirs; therefore, to optimize the oil production rate and final oil recovery, systematical optimization of every detail based on the condition of a specific reservoir is of key importance. In this paper, physical simulations were first conducted to select the best recovery methods for the target area based on the static geophysical model under the guidance of reservoir engineering theory. Then, detailed development variants for each method were determined by numerical simulation with the support of data obtained from previous pilot tests (polymer gel flooding and thermal fluid huff and puff) conducted in this area. Three exploitation methods were developed for the target well group, including polymer gel flooding (conformance control, Pattern 1), steam huff and puff (thermal recovery method, Pattern 2), and a combination of polymer gel flooding and steam huff and puff (conformance control and thermal recovery, Pattern 3). The numerical simulation result also showed that Pattern 3 yielded the highest oil recovery. Moreover, the amount of additional oil being recovered by applying Pattern 3 was even higher than the total additional oil being extracted by Patterns 1 and 2. In addition, sensitivity analysis was conducted to rank the most important parameters based on the three Patterns. At last, it is thought that the synergistic effect between conformance control and thermal recovery made more oil recovered, which was intuitively clarified in the mechanism analysis.

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Livescu, S., L. J. J. Durlofsky, and K. Aziz. "A Semianalytical Thermal Multiphase Wellbore-Flow Model for Use in Reservoir Simulation." SPE Journal 15, no. 03 (April 28, 2010): 794–804. http://dx.doi.org/10.2118/115796-pa.

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Summary The detailed interactions between the reservoir and the wellbore are especially important in thermal processes such as steamflooding and in-situ upgrading. These linkages, therefore, must be captured in thermal simulations. Although fully coupled thermal wellbore-/reservoir-flow simulators have been developed, the implementation of the thermal well model is somewhat complicated, and the simulations are computationally demanding. In this paper, we present a semianalytical treatment that enables the extension of existing isothermal wellbore-flow models to the nonisothermal case. The procedure entails the use of analytical solutions for wellbore temperature applied in conjunction with numerical solutions of the reservoir mass- and energy-balance equations coupled with wellbore mass- and momentum-balance equations. The approach thus enables a degree of decoupling between the wellbore flow and energy problems. We proceed by first presenting analytical solutions for wellbore temperature, developed under various assumptions (these basic solutions have been obtained previously). We then describe the use of one of these solutions, which allows for general variation of in-situ phase fraction and other properties along the wellbore, within the semianalytical context. The implementation of the overall method into a general purpose research simulator is also described. Results are presented for several cases involving multiphase flow in monobore and multilateral wells. Close agreement with reference solutions, obtained from a fully coupled thermal wellbore/reservoir model, is demonstrated for all of the examples. The semianalytical treatment is additionally shown to provide comparable or improved computational efficiency relative to the fully coupled model.

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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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Stone, T. W., J. Bennett, D. H. S. Law, and J. A. Holmes. "Thermal Simulation With Multisegment Wells." SPE Reservoir Evaluation & Engineering 5, no. 03 (June 1, 2002): 206–18. http://dx.doi.org/10.2118/78131-pa.

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Summary The extension of a previously reported well model to compositional and thermal applications is discussed. This multisegment, multibranching wellbore model has been fully coupled to a commercial reservoir simulator that can operate in black-oil, compositional, or thermal modes. In this paper, the discussion will focus on thermal, heavy-oil applications in which simulation requires a better representation of the wellbore geometry and the physics of fluid flow and heat transfer. Introduction Gravity-drainage processes with possible steam (SAGD) or gas vapor (VAPEX) assistance and other recovery technologies often require the use of long horizontal wells with flow in an inner tubing and outer annulus.1–3 Thermal studies that simulate horizontal wells have been discussed by many authors. Recovery techniques include cyclicsteam projects,4–10 dual-well SAGD,11 and single-well SAGD.12 In these studies, the oils are heavy (970 to 1014 kg/m3; 14 to 8°API), with viscosities ranging from 2,000 cp at 32°C in California fields up to 1,000,000 cp at 12°C for oils found at the UTF project13 in the Athabasca tar sands deposit. These studies have, for the most part, used the conventional wellbore line source/sink model available in any thermal simulator. Simulation technology for horizontal wells has improved dramatically since the late 1980s. At this time, Stone et al.14 described a horizontal well model that featured a mechanistic multiphase fluid-flow model in the wellbore and allowed flow simultaneously in an inner tubing and outer annulus. This was designed to handle simulations in the near-wellbore region of a dual-well SAGD process and, because of the more detailed flow regime map, could not handle larger-scale simulations for stability reasons. Also during this time period, Long et al.15 carried out the Seventh SPE Comparative Solution Project concerning the modeling of horizontal wells in reservoir simulation. A variety of methods was used by the participants to model the inflow into the horizontal well model. These included the use of an inflow performance relationship (IPR) with a separate well model or direct coupling by modeling the well as part of the grid. Similarly, there were various wellbore hydraulics models ranging from a constant-pressure line sink to friction pressure-drop relations or simple functional fits of published holdup correlations. All of these horizontal well models were designed to run robustly and stably in large-scale field simulations. However, some were limited in their ability to calculate a multiphase pressure drop, others in not allowing the wellbore model geometry to correspond to the engineering design of the well rather than to the simulation grid. Some methods allowed multiphase pressure drops with explicit updates or other approximations. Recently, Tan et al.16 have described a fully coupled discretized thermal wellbore model with the ability to simulate flow in casing/annulus wellbore cells. Estimates of the relative flow rates are made based on phase saturations and straight-line relative permeability curves. These estimates are passed to a subroutine that calculates flow rates from the correlated Beggs et al.17 measurements. Wellbore cells are connected to reservoir cells. A multisegment well model that can simulate flow in advanced wells was discussed by Holmes et al.18,19 This model, implemented in a commercial black-oil simulator, is able to determine the local flowing conditions (the flow rate and pressure of each fluid) throughout the well. It allows for pressure losses along the wellbore and across any flow-control devices. In addition to being fully implicitly coupled, with crossflow modeling and the standard group control facilities, horizontal wells, multilateral wells, and "smart" wells containing flow-control devices can also be modeled. The trajectory is not constrained by the simulation grid. For example, the wellbore may run outside the grid or across layers. Properties and geometry can be updated at any time in the simulation. In this paper, we first describe the implementation and enhancements to the implicit multisegment well model discussed in Ref. 18 that allow this model to run in compositional and thermal modes. In these modes, the equation of state (EOS) or thermal K-value treatment of the fluid pressure/volume/temperature (PVT) is extended to the wellbore flow. Phase volumes are computed in each segment and are then used to calculate the multiphase pressure drop. In thermal mode, an enhancement allows the definition of heat transfer coefficients, which permit heat loss to the reservoir, to another segment, or to the overburden. Another enhancement allows individual segments to inject or produce fluids, which permits the direct modeling of gas lift, downhole water pumps, or circulating wells, available in any mode. It is important in compositional, and especially thermal, wellbore simulations to provide an accurate initial estimate of the well solution; otherwise, there can be convergence problems. A method for predicting the initial state within the well is also shown later. We then present four case studies. Each case study has been set up from published engineering analyses of fields in western Canada and California, U.S.A. The well model used in these studies is considerably more detailed than that in the original published simulation work. Not only are the wellbore hydraulics more accurately modeled with multiphase flow models, but the geometry of the wells is also specified in more detail. Wellbore geometry includes the ability to run the well outside the simulation grid, allowing the modeling of heat loss from a steam-injection well to the formation, between the surface and the simulation grid. Also, an undulating well trajectory can be specified and is demonstrated in one of the studies. Fluid flow down an inner tubing and back along an outer completed annulus is demonstrated in three of the studies, in which heat transfer occurs between the inner tubing and the outer annulus and between the annulus and the formation. Two of these studies contain a segment at the heel of a horizontal annulus that removes fluids to an external sink, allowing part of the circulating fluids to return to the surface while the remainder are injected, produced, or stored in the wellbore. Where possible, differences are shown between the multisegment model and a standard line source/sink model that demonstrate the effects of modeling the improved wellbore physics. Description of the Multisegment Well Model The multisegment well model reported by Holmes et al.18 was originally implemented in a black-oil simulator. It uses four main variables: a total fluid-flow rate through the segment, weighted fractional flows of both water and gas, and pressure in the segment.

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Sarda, S., L. Jeannin, R. Basquet, and B. Bourbiaux. "Hydraulic Characterization of Fractured Reservoirs: Simulation on Discrete Fracture Models." SPE Reservoir Evaluation & Engineering 5, no. 02 (April 1, 2002): 154–62. http://dx.doi.org/10.2118/77300-pa.

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Summary Advanced characterization methodology and software are now able to provide realistic pictures of fracture networks. However, these pictures must be validated against dynamic data like flowmeter, well-test, interference-test, or production data and calibrated in terms of hydraulic properties. This calibration and validation step is based on the simulation of those dynamic tests. What has to be overcome is the challenge of both accurately representing large and complex fracture networks and simulating matrix/ fracture exchanges with a minimum number of gridblocks. This paper presents an efficient, patented solution to tackle this problem. First, a method derived from the well-known dual-porosity concept is presented. The approach consists of developing an optimized, explicit representation of the fractured medium and specific treatments of matrix/fracture exchanges and matrix/matrix flows. In this approach, matrix blocks of different volumes and shapes are associated with each fracture cell depending on the local geometry of the surrounding fractures. The matrix-block geometry is determined with a rapid image-processing algorithm. The great advantage of this approach is that it can simulate local matrix/fracture exchanges on large fractured media in a much faster and more appropriate way. Indeed, the simulation can be carried out with a much smaller number of cells compared to a fully explicit discretization of both matrix and fracture media. The proposed approach presents other advantages owing to its great flexibility. Indeed, it accurately handles the cases in which flows are not controlled by fractures alone; either the fracture network may be not hydraulically connected from one well to another, or the matrix may have a high permeability in some places. Finally, well-test cases demonstrate the reliability of the method and its range of application. Introduction In recent years, numerous research programs have been focusing on the topic of fractured reservoirs. Major advances were made, and oil companies now benefit from efficient methodologies, tools, and software for fractured reservoir studies. Nowadays, a study of a fractured reservoir, from fracture detection to full-field simulation, includes the following main steps: geological fracture characterization, hydraulic characterization of fractures, upscaling of fracture properties, and fractured reservoir simulation. Research on fractured reservoir simulation has a long history. In the early 1960s, Barenblatt and Zheltov1 first introduced the dual-porosity concept, followed by Warren and Root,2 who proposed a simplified representation of fracture networks to be used in dual-porosity simulators. Based on this concept, reservoir simulators3 are now able to correctly reproduce the main driving mechanisms occurring in fractured reservoirs, such as water imbibition, gas/oil and water/oil gravity drainage, molecular diffusion, and convection in fractures. Even single-medium simulators can perform fractured reservoir simulation when adequate pseudocapillary pressure curves and pseudorelative permeability curves can be input. Indeed, except for particular cases such as thermal recovery processes, full-field simulation of fractured reservoirs is no longer a problem. Geological characterization of fractures progressed considerably in the 1990s. The challenge was to analyze and integrate all the available fracture data to provide a reliable description of the fracture network both at field scale and at local reservoir cell scale. Tools have been developed for merging seismic, borehole imaging, lithological, and outcrop data together with the help of geological and geomechanical rules.3 These tools benefited from the progress of seismic acquisition and borehole imaging. Indeed, accurate seismic data lead to reliable models of large-scale fracture networks, and borehole imaging gives the actual fracture description along the wells, which enables a reliable statistical determination of fracture attributes. Finally, these tools provide realistic pictures of fracture networks. They are applied successfully in numerous fractured-reservoir studies. The upscaling of fracture properties is the problem of translating the geological description of fracture networks into reservoir simulation parameters. Two approaches are possible. In the first one, the fractured reservoir is considered as a very heterogeneous matrix reservoir; therefore, one applies the classical techniques available for heterogeneous single-medium upscaling. The second approach is based on the dual-porosity concept and consists of upscaling the matrix and the fracture separately. Based on this second approach, methodologies and software were developed in the 1990s to calculate equivalent fracture parameters with respect to the dual-porosity concept (i.e., a fracture-permeability tensor with main flow directions and anisotropy and a shape factor that controls the matrix/fracture exchange kinetics3–5). For a given reservoir grid cell, the upscaling procedures consist of generating the corresponding 3D discrete fracture network and computing the equivalent parameters from this network. In particular, the permeability tensor is computed from the results of steady-state flow simulations in the discrete fracture network alone (without the matrix).

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Lorimer, Shelley, Govind Kumar, and Sherif Abdelkareem. "Effect of Solvent Concentration on Scaling Butane Solvent Enhanced Oil Recovery Processes Using Reservoir Simulation." Diffusion Foundations 27 (May 2020): 136–65. http://dx.doi.org/10.4028/www.scientific.net/df.27.136.

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Understanding scaling of enhanced oil/bitumen recovery processes is essential in moving laboratory scale experimental results to field scale. Scaling theory for thermal processes is well understood and has been applied to steam processes. However, scaling of hybrid steam (thermal) /solvent (mass transfer) processes is still not well defined nor well understood. This paper investigates the scaling behavior of hybrid steam/butane gravity drainage processes using reservoir simulation (commercial thermal compositional simulator CMG STARSTM). Previous research has used reservoir simulation to confirm scaling groups for waterflooding. A similar strategy was used in this study whereby the scaling of a hybrid (steam) solvent oil recovery process was examined using reservoir simulations at three different reservoir scales: lab scale, semi-field scale and field scale to examine the influence of the mass transfer mechanisms of diffusion and dispersion on the scalability of the process. In particular, the influence of butane solvent concentration on scaling a steam/butane gravity drainage process was investigated by considering several butane mole fraction concentrations injected with steam (1%, 2%, 5%, 7%, 10%, 15%, 21%, 25% and 50%). Temperature contours, and mole fraction contours of butane in both the oil and gas phases were examined for various solvent injection concentrations to examine scalability. Numerical results are provided with no diffusion and dispersion, diffusion only, dispersion only and with both diffusion and dispersion added to the simulations. Results confirmed scalability of the process with no capillary effects when the simulation results were non-dimensionalized, although there were some issues with material balance errors in some of the simulation results particularly at high solvent concentrations. For low injection concentrations, the contours were almost identical (indicating scalability) for the three scales for the operating condition studied. In addition, capillary effects were also studied, and similar to scaling thermal processes, the capillarity effects influenced scalability of the process under the conditions studied particularly at higher injection concentrations. Scalability using reservoir simulation was generally preserved with low injection concentrations, but unusual behavior was observed at higher injection concentrations (>5%). Oil recovery curves were non-dimensionalized to make comparisons amongst the three scales. The oil recovery curves displayed an unusual S-shaped behavior at higher injection concentrations when capillary effects were included especially for the lab and semi-field scales. In all cases when all of the mechanisms are included (diffusion, dispersion and capillary effects), Scale 1 shows a much faster recovery than Scale 3 which suggests that the lab scale might temporally overestimate the field scale recovery for this particular process scenario.

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Xin, SUN, WANG Xue, XU Yan, XIE Yue, and HUANG Tinglin. "Numerical simulation and verifications on thermal stratification in a stratified reservoir." Journal of Lake Sciences 27, no. 2 (2015): 319–26. http://dx.doi.org/10.18307/2015.0217.

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Tortike, W. S., and S. M. Farouq Ali. "Saturated-Steam-Property Functional Correlations for Fully Implicit Thermal Reservoir Simulation." SPE Reservoir Engineering 4, no. 04 (November 1, 1989): 471–74. http://dx.doi.org/10.2118/17094-pa.

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Han, Bo-Ping, Joan Armengol, Juan Carlos Garcia, Marta Comerma, Montse Roura, Josep Dolz, and Milan Straskraba. "The thermal structure of Sau Reservoir (NE: Spain): a simulation approach." Ecological Modelling 125, no. 2-3 (January 2000): 109–22. http://dx.doi.org/10.1016/s0304-3800(99)00176-3.

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Li, Yang, Ting-lin Huang, Zi-zhen Zhou, Sheng-hai Long, and Hai-han Zhang. "Effects of reservoir operation and climate change on thermal stratification of a canyon-shaped reservoir, in northwest China." Water Supply 18, no. 2 (June 24, 2017): 418–29. http://dx.doi.org/10.2166/ws.2017.068.

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Abstract Thermal stratification has a significant impact on water quality and ecological characteristics. Reservoir operation and climate change have an effect on the thermal regime. The Jinpen Reservoir is a large canyon-shaped reservoir located in Shaanxi Province with a strong thermal stratification, which resulted in an anaerobic condition in the hypolimnion. We used a hydrodynamic module based on MIKE 3 to simulate the thermal structure of the Jinpen Reservoir and study the relationship between the thermal regime, reservoir operation and climate change. Based on the daily hydrological and climatic data from 2004 to 2013, we made 13 hypothetical simulated conditions that included extreme change of inflow volume, water level, air temperature, radiation, inflow water temperature and selective withdrawal to explore the effect of different factors on the thermal regime. The results showed that the period of thermal stratification, water column stability and surface water temperature were influenced by these factors. With the increase of air temperature, the simulation results indicated a stronger thermal stratification and a higher surface water temperature, which could cause water safety problems. Deep withdrawal could decrease water column stability and prompt water column mixing early, which could be used by reservoir managers to optimize the reservoir operation.

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Malinouskaya, Iryna, Christophe Preux, Nicolas Guy, and Gisèle Etienne. "Impact of geomechanical effects during SAGD process in a meander belt." Oil & Gas Sciences and Technology – Revue d’IFP Energies nouvelles 73 (2018): 17. http://dx.doi.org/10.2516/ogst/2018011.

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In the reservoir simulations, the geomechanical effects are usually taken into account to describe the porosity and the permeability variations. In this paper, we present a new method, patented by authors, which allows to model the geomechanical effects also on the well productivity index. The Steam Assisted Gravity Drainage (SAGD) method is widely used for the heavy oil production. A very high variation in pressure and temperature play a significant role on the petrophysical properties and may impact the productivity estimation. In this paper we develop a new simplified geomechanical model in order to account for the thermal and pressure effects on the porosity, permeability and the productivity index during the reservoir simulation. At the current state, these dependencies are defined using semi-analytical relationships. The model is applied to a meandering fluvial reservoir based on 3D outcrop observations. The productivity is found underestimated if the pressure and temperature effects on the petrophysical properties are ignored in the reservoir simulation. Moreover, this study shows an important impact of thermal effects on the productivity estimation. The results of this work show that it is essential to properly take into account the geomechanical effects on the petrophysical properties and also on the productivity index for a better productivity estimation.

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Ma, Guang Yu, Bin Bin Wu, and Hong Jiang. "The Impacts of Water Transfer on Thermal Structure of Shallow Reservoir." Applied Mechanics and Materials 477-478 (December 2013): 864–69. http://dx.doi.org/10.4028/www.scientific.net/amm.477-478.864.

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A two-dimensional numerical model was built for the typical shallow reservoir with serious thermal pollution in the North China Plain. After calibration and validation, four scenarios were developed to study the impacts of water transfer on thermal structure. Model results showed that the hydrodynamic and water temperature could be well simulated. The effects of water transfer on thermal structure showed in decreasing temperature rises, which was more remarkable for regions far away from the releasing point of thermal discharge. In terms of reducing temperature, 45.5 m3/s was the most efficient inflow rate among the four representative flow rates. This study provides useful information for reservoir sustainable management. Keywords: water transfer, temperature, numerical simulation, Douhe reservoir.

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Gallardo, Enrique, and Clayton V. Deutsch. "Approximate Physics-Discrete Simulation of the Steam-Chamber Evolution in Steam-Assisted Gravity Drainage." SPE Journal 24, no. 02 (December 31, 2018): 477–91. http://dx.doi.org/10.2118/194016-pa.

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Summary Steam-assisted gravity drainage (SAGD) is a thermal-recovery process to produce bitumen from oil sands. In this technology, steam injected in the reservoir creates a constantly evolving steam chamber while heated bitumen drains to a production well. Understanding the geometry and the rate of growth of the steam chamber is necessary to manage an economically successful SAGD project. This work introduces an approximate physics-discrete simulator (APDS) to model the steam-chamber evolution. The algorithm is formulated and implemented using graph theory, simplified porous-media flow equations, heat-transfer concepts, and ideas from discrete simulation. The APDS predicts the steam-chamber evolution in heterogeneous reservoirs and is computationally efficient enough to be applied over multiple geostatistical realizations to support decisions in the presence of geological uncertainty. The APDS is expected to be useful for selecting well-pair locations and operational strategies, 4D-seismic integration in SAGD-reservoir characterization, and caprock-integrity assessment.

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SUZUKI, Koichi, Hiroshi SUZUKI, and Takeru OGATSU. "Application of thermal reservoir simulation technology to steamflood field pilot test in heavy oil reservoir. (Part 1)." Journal of the Japanese Association for Petroleum Technology 55, no. 6 (1990): 442–51. http://dx.doi.org/10.3720/japt.55.442.

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Yang, Xing Ping, Xiao Lin Chang, and Xing Hong Liu. "FEM Simulation of Temperature and Thermal Stress of Xiaowan Arch Dam." Applied Mechanics and Materials 212-213 (October 2012): 887–90. http://dx.doi.org/10.4028/www.scientific.net/amm.212-213.887.

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Taking all the effects into account of thermal and mechanical properties, construction process, environment temperature, arch-closure and reservoir impounding orders, three dimension (3D) finite element methods(FEM) was adopted to simulate the whole construction process for temperature changing and thermal stress distribution of the dam. Typically, the results of the highest 22nd monolith were analyzed, from which the general law for both temperature field and thermal stress was acquired. And the results are valuable for temperature control of Xiaowan high arch dam.

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Chen, Qing, Margot G. Gerritsen, and Anthony R. Kovscek. "Effects of Reservoir Heterogeneities on the Steam-Assisted Gravity-Drainage Process." SPE Reservoir Evaluation & Engineering 11, no. 05 (October 1, 2008): 921–32. http://dx.doi.org/10.2118/109873-pa.

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Summary The success of steam-assisted gravity drainage (SAGD) has been demonstrated by both field and laboratory studies mostly on the basis of homogeneous reservoirs and reservoir models. A comprehensive understanding of the effects of reservoir heterogeneities on SAGD performance is required, however, for wider and more-successful implementation. This work presents a numerical investigation of the effects of reservoir heterogeneities on SAGD using a stochastic model of shale distribution. Two flow regions, the near-well region (NWR) and the above-well region (AWR), are identified to decouple the complex effects of reservoir heterogeneities on the SAGD process. Numerical simulations are conducted with various realizations of shale distribution to compare SAGD performance in terms of the effects of NWR and AWR. Hydraulic fracturing is proposed to enhance steam-chamber development for reservoirs with poor vertical communication, and the feasibility of hydraulic fracturing is discussed in terms of in-situ stress and well orientation. Fracturing both injectors and producers is found to improve steam distribution, oil production rate, and the oil-steam ratio. Introduction Vast quantities of heavy- and extraheavy-oil (bitumen) resources have been discovered worldwide. For example, an estimated original heavy oil in place of more than 1.8 trillion bbl is present in Venezuela, 1.7 trillion bbl in Alberta, Canada, and 20 to 25 billion bbl on the North Slope of Alaska (Burton et al. 2005). Because of the significant viscosity of these crudes at reservoir temperature, the technical and economic recovery of these resources presents a significant challenge. With recent advances in horizontal-well technology, steam-based in-situ recovery methods, aimed at thermal viscosity reduction, have emerged for the exploitation of these resources (Butler 2001). Of all the thermal methods, SAGD appears to be quite promising, especially for bitumen. In a typical SAGD process, two horizontal wells are placed close to the bottom of a formation, with one well a short vertical distance (4-10 m) away from the other. Steam is injected continuously into the upper well and rises in the formation, forming a steam chamber. Cold oil surrounding the steam chamber is heated, becomes mobile as its temperature increases, and flows together with condensate along the chamber boundaries toward the lower well that functions as a producer (Butler 1998). The SAGD technique enjoys many advantages over other thermal methods, especially the conventional steamflooding methods. SAGD overcomes the shortcomings of steam override by using only gravity as the driving mechanism, which leads to a stable displacement and a potentially high oil recovery. Moreover, the heated oil remains hot and movable as it flows toward the production well, whereas, in conventional steamflooding, the oil displaced from the steam chamber cools, and consequently the oil-phase viscosity increases, as the oil flows to the production well. In order to design an effective SAGD process, an understanding of the complex physics of SAGD and reliable predictions of its performance are essential. A vast literature on the SAGD concept has developed since it was first introduced by Butler and his colleagues in the late 1970s (Butler and Stephens 1981; Butler et al. 1981). Butler developed a gravity-drainage theory on the basis of several assumptions and derived a semianalytical numerical solution to predict the oil-drainage rate. He and his coworkers also reported experimental data obtained with a scaled visual model. Reis (1992) proposed modifications to Butler's gravity-drainage model by using an empirical dimensionless-temperature coefficient and the maximum velocity, and Akin (2005) also modified the model by incorporating asphaltene-content-dependent viscosity to match the experimental data in the literature better. Nasr et al. (2000) studied steam-liquid countercurrent and cocurrent flows for different permeabilities and initial gas saturations with a nonsteady-state, laboratory steam-front dynamic-tracking technique. Numerical simulation has been used widely to investigate the physical process and practical operation of SAGD. For example, Edmunds (1998) analyzed SAGD steam-trap control with 2D and 3D simulation models. He found that establishing a liquid-saturated leg above the producer was feasible by controlling the temperature of the produced fluid. The producer is shut in when the temperature of the produced fluid approaches the temperature of the injected fluid. These analytical and numerical studies, however, were generally performed for homogeneous, isotropic reservoirs. In reality, no reservoir is homogeneous because of natural geological features, such as shale, faults, and fractures. One example is the oil-sand deposit in Peace River, Alberta, Canada. It contains a good deal of marine shale and mudstone that form continuous and discontinuous shale barriers throughout the formation (Webb et al. 2005). The heterogeneity introduced by the shale barriers and other geological features plays an important role in the propagation of steam (Richardson et al. 1978). Therefore, without understanding the effects of reservoir heterogeneities, SAGD results for homogeneous systems cannot be applied directly to provide accurate, reliable predictions for field-type systems. During the past decades, several researchers have investigated the role of reservoir heterogeneities on steam-chamber development for a SAGD process. Joshi and Threlkeld (1985) studied reservoirs with shale barriers and experimentally compared the effects of various well-configuration schemes and vertical fractures. Yang and Butler (1992) conducted SAGD experiments with reservoirs of two different types: reservoirs with thin shale layers and reservoirs with horizontal layers of different permeabilities. These studies were subject to experimental limitations. Reservoir heterogeneities were simulated by including a limited number of impermeable barriers at designated locations. Given the complex geological nature of shale, it would be better instead to use a stochastic model based on geostatistical methods (Pooladi-Darvish and Mattar 2002) to represent the shale distribution. This study investigates the effects of reservoir heterogeneity on SAGD from a simulation perspective. We use a stochastic model of the shale and sand distribution and a fully featured thermal reservoir simulator. To interpret the complex effects of reservoir heterogeneity on the SAGD process, two flow regions are identified according to the characteristics of flows associated within the steam chamber. Numerical simulations are conducted with a number of equal-probability realizations in 2D and 3D to compare SAGD performance. The intent of these simulations is to instruct regarding the thermal gravity-drainage-process physics rather than to match the oil production of a particular reservoir. For reservoirs with poor vertical communication, hydraulic fracturing is proposed to enhance steam-chamber development, and the feasibility of hydraulic fracturing is discussed in terms of in-situ stresses and well orientations.

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Baldwin, J. O., and G. G. Wilcox. "PC-Based Quick-Look Graphical Postprocessing in Reservoir Simulation for Thermal Recovery." SPE Computer Applications 5, no. 02 (March 1, 1993): 8–16. http://dx.doi.org/10.2118/22310-pa.

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Ma, Yuanle, and Zhangxin Chen. "Parallel computation for reservoir thermal simulation of multicomponent and multiphase fluid flow." Journal of Computational Physics 201, no. 1 (November 2004): 224–37. http://dx.doi.org/10.1016/j.jcp.2004.05.014.

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Huang, Shi Jun, Ping Hu, and Qiu Li. "Study on Heating Zone and Producing Zone of Cyclic Steam Stimulation with Horizontal Well in Heavy Oil Reservoir." Advanced Materials Research 594-597 (November 2012): 2438–41. http://dx.doi.org/10.4028/www.scientific.net/amr.594-597.2438.

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In this paper, employing reservoir simulation and mathematical analysis methods, considering typical heavy oil reservoir and fluid thermal properties, the heating and producing shape of thermal recovery with horizontal well for different heavy oil reservoirs including ordinary, extra and super heavy oil are investigated based on the modification of thermal recovery parameters of different viscosity. By introducing heating radius and producing radius and considering the coupling effect of temperature, pressure and oil saturation fields, a quantitative expression between heating radius/producing radius and oil viscosity, formation thickness is presented, so is the impact of oil viscosity on the heating radius. Results shows that for Cyclic Steam Stimulation, the producing radius of horizontal well is bigger than its heating radius for light oil, both of which, however, shrink with higher viscosity. Beyond a critical viscosity, where the heating radius equals to the producing radius, the heating radius of horizontal well would be bigger than its producing radius. More over, the critical viscosity shows tight relationship to the formation thickness.

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Zhang, Liming, Zekun Deng, Kai Zhang, Tao Long, Joshua Desbordes, Hai Sun, and Yongfei Yang. "Well-Placement Optimization in an Enhanced Geothermal System Based on the Fracture Continuum Method and 0-1 Programming." Energies 12, no. 4 (February 21, 2019): 709. http://dx.doi.org/10.3390/en12040709.

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The well-placement of an enhanced geothermal system (EGS) is significant to its performance and economic viability because of the fractures in the thermal reservoir and the expensive cost of well-drilling. In this work, a numerical simulation and genetic algorithm are combined to search for the optimization of the well-placement for an EGS, considering the uneven distribution of fractures. The fracture continuum method is used to simplify the seepage in the fractured reservoir to reduce the computational expense of a numerical simulation. In order to reduce the potential well-placements, the well-placement optimization problem is regarded as a 0-1 programming problem. A 2-D assumptive thermal reservoir model is used to verify the validity of the optimization method. The results indicate that the well-placement optimization proposed in this paper can improve the performance of an EGS.

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Han, Seoeum, Sangyoon Lee, and Bok Jik Lee. "Numerical Analysis of Thermochemical Nonequilibrium Flows in a Model Scramjet Engine." Energies 13, no. 3 (January 31, 2020): 606. http://dx.doi.org/10.3390/en13030606.

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This numerical study was conducted to investigate the flow properties in a model scramjet configuration of the experiment in the T4 shock tunnel. In most numerical simulations of flows in shock tunnels, the inflow conditions in the test section are determined by assuming the thermal equilibrium of the gas. To define the inflow conditions in the test section, the numerical simulation of the nozzle flow with the given nozzle reservoir conditions from the experiment is conducted by a thermochemical nonequilibrium computational fluid dynamics (CFD) solver. Both two-dimensional (2D) and three-dimensional (3D) numerical simulations of the flow in a model scramjet were conducted without fuel injection. Simulations were performed for two types of inflow conditions: one for thermochemical nonequilibrium states obtained from the present nozzle simulation and the other for the data available using the thermal equilibrium and chemical nonequilibrium assumptions. The four results demonstrate the significance of the modelling approach for choosing between 2D or 3D, and thermal equilibrium or nonequilibrium.

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Iranshahr, A., D. V. V. Voskov, and H. A. A. Tchelepi. "Tie-Simplex Parameterization for EOS-Based Thermal Compositional Simulation." SPE Journal 15, no. 02 (March 3, 2010): 545–56. http://dx.doi.org/10.2118/119166-pa.

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Summary Thermodynamic equilibrium computations are usually the most time-consuming component in compositional reservoir flow simulation. A compositional space adaptive tabulation (CSAT) approach was developed as a preconditioner for equation of state (EOS) computations in isothermal compositional simulation. The compositional space is decomposed into sub- and supercritical regions. In the subcritical region, we adaptively parameterize the compositional space using a small number of tie-lines, which are assembled into a table. The critical surface is parameterized and used to identify supercritical compositions. The phase-equilibrium information for a composition is interpolated as a function of pressure using the tie-line table. We extend the CSAT approach to thermal problems. Given an overall composition at a fixed temperature, the boundary between sub- and supercritical pressures is represented by the critical tie-line and the corresponding minimal critical pressure (MCP). A small set of subcritical tie-lines is computed and stored for a given temperature. This process is repeated for the pressure and temperature ranges of interest, and a coarse (regular) tie-line table is constructed. Close to the critical boundary, a refined tie-line table is used. A combination of regular and refined interpolation improves the robustness of the tie-line search procedure and the overall efficiency of the computations. Several challenging problems, including an unstructured heterogeneous discrete fracture field model with 26 components, are used to demonstrate the robustness and efficiency of this general tie-line-based parameterization method. Our results indicate that CSAT provides accurate treatment of the near-critical region. Moreover, the computational efficiency of the method is at least an order of magnitude better than that of standard EOS-based reservoir simulation approaches. We also show the efficiency gains relative to standard techniques as a function of the number of gridblocks in the simulation model.

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Suzuki, Koichi. "Application of thermal reservoir simulation technology to a steamflood field pilot test in a heavy oil reservoir. (Part2)." Journal of the Japanese Association for Petroleum Technology 58, no. 3 (1993): 187–98. http://dx.doi.org/10.3720/japt.58.187.

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Sidders, J. A., D. G. Tilley, and P. J. Chappie. "Thermal-Hydraulic Performance Prediction in Fluid Power Systems." Proceedings of the Institution of Mechanical Engineers, Part I: Journal of Systems and Control Engineering 210, no. 4 (November 1996): 231–42. http://dx.doi.org/10.1243/pime_proc_1996_210_462_02.

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This paper presents a modelling approach to the study of thermal-hydraulic performance in fluid power systems. A set of lumped parameter mathematical models are developed which are based on conservation of mass and energy for the system. The theoretical basis and modelling strategy are discussed for an open circuit containing a hydraulic pump, loading valve, heat exchanger and reservoir. Simulation results are presented which show a comparison of model/rig performance, and the agreement obtained demonstrates the validity of the modelling approach. It is shown that the thermal response is dominated by the reservoir heat capacity and that close correspondence between the model and rig is only achievable with accurate hydraulic performance models.

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Zagayevskiy, Yevgeniy, and Clayton V. Deutsch. "Application of Grid-Free Geostatistical Simulation to a Large Oil-Sands Reservoir." SPE Reservoir Evaluation & Engineering 19, no. 03 (April 4, 2016): 367–81. http://dx.doi.org/10.2118/180917-pa.

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Summary Geostatistical simulation is performed for reservoir characterization to depict local variability in the modeled properties. The conventional simulation methods are implemented in a grid-dependent manner that makes regridding of realizations, refinement of existing grids, and the simulation on irregular grids challenging. The grid-free-simulation (GFS) method has been recently developed for flexible reservoir characterization. The geostatistical realizations of a reservoir are expressed as an analytical function of the coordinates of the simulation locations and, thus, are infinitely resolvable. The resulting model is conditioned to primary scattered point-scale hard data and secondary exhaustively sampled block-scale soft data. The former data are sampled along wells, whereas the latter data are from seismic surveys. The GFS methodology is applied to the Firebag oil-sands thermal project operated in northern Alberta, Canada. The conditioning data are point-scale core measurements, log observations, and block-scale acoustic impedance (AI). The models of correlated porosity, permeability, and water saturation attributes are constructed on three different grids by facies and are consistent with each other. These models are intended for resource estimation, reserves estimation, and subsequent-flow simulation, respectively. The modeling results of the grid-independent simulation method are promising for industrial application to petroleum reservoir characterization.

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Livescu, S., L. J. Durlofsky, K. Aziz, and J. C. Ginestra. "A fully-coupled thermal multiphase wellbore flow model for use in reservoir simulation." Journal of Petroleum Science and Engineering 71, no. 3-4 (April 2010): 138–46. http://dx.doi.org/10.1016/j.petrol.2009.11.022.

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Yuan, Jianwei, Ruizhong Jiang, Yongzheng Cui, Jianchun Xu, Qiong Wang, and Wei Zhang. "The numerical simulation of thermal recovery considering rock deformation in shale gas reservoir." International Journal of Heat and Mass Transfer 138 (August 2019): 719–28. http://dx.doi.org/10.1016/j.ijheatmasstransfer.2019.04.098.

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Preux, Christophe, Iryna Malinouskaya, Quang-Long Nguyen, Eric Flauraud, and Simon Ayache. "Reservoir-Simulation Model with Surfactant Flooding Including Salinity and Thermal Effect, Using Laboratory Experiments." SPE Journal 25, no. 04 (March 23, 2020): 1761–70. http://dx.doi.org/10.2118/196663-pa.

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Summary Surfactant injection is a process used by oil companies to improve the oil-recovery factor. Surfactant modifies the interfacial tension (IFT) and to a lesser extent the mobility-reduction factor. Both the salinity and the temperature will affect the efficiency of the surfactant. As a result, a series of laboratory experiments are commonly conducted to evaluate dependency. However, these experiments are expensive and time consuming. In this paper, we present numerical simulations coupled to a model that allows taking into account the modification of the IFT and the mobility-reduction factor caused by both the salinity and temperature variations during surfactant injection. In this work, we propose a coupled numerical model using five equations: two transport equations of water and oil phases modelized by Darcy's law, two transport equations for the surfactant and the salinity (the surfactant and the salinity are transported only in the water phase), and one energy-conservation equation to take into account the thermal effect on surfactant flooding. The system of equations includes the salinity and temperature effects on the surfactant adsorption and thermal degradation, as well as the IFT. Thus, this model allows improving the analysis of thermal corefloods or reservoir operations resulting from the surfactant injection. On the basis of corefloods, we use the coupled model to reproduce laboratory experiments. We analyze the interaction phenomena between the surfactant, salinity, and temperature. Then, we demonstrate a competition between two phenomena: the thermal effect on the viscosity of water and the effect of surfactant on the mobility of water. This study highlights the efficiency of numerical simulations for the analysis and choice of the surfactant applied to the given reservoir and well conditions.

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Rubin, Barry, and W. Lloyd Buchanan. "A General Purpose Thermal Model." Society of Petroleum Engineers Journal 25, no. 02 (April 1, 1985): 202–14. http://dx.doi.org/10.2118/11713-pa.

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Abstract This paper describes a fully implicit four-phase (oil, water, gas, solid fuel) numerical reservoir model for simulating hot water injection, steam injection, dry combustion, and wet combustion in one, two, or three dimensions and in either a Cartesian, radial, or curvilinear geometry. The simulator rigorously models fluid flow, heat transfer (convective and conductive), heat loss to formation, fluid vaporization/condensation, and chemical reactions. Any number of oil or gas phase components may be specified, along with any number of solid phase components (fuel and catalysts). The simulator employs either D4 Gaussian elimination or powerful incomplete factorization methods to solve the often poorly conditioned matrix problems. An implicit well model is coupled to the simulator, where reservoir unknowns and well block pressures are primary variables. This paper includescomparisons of the numerical model's results with previously reported laboratory physical models' results for steam and combustion and physical models' results for steam and combustion andanalytical solutions to a hot waterflood problem. In addition, an actual field-scale history match is presented for a single-well steam stimulation problem. Introduction Recent papers by Crookston et al., Youngren Rubin and Vinsome, and Coats have outlined the current trend in thermal process simulation. The trend has been the development of more implicit, more comprehensive finite-difference simulators. Youngren describes a model based on a highly implicit steam model. The components representing air and combustion gases are treated explicitly. Burning reactions are handled not through rates but through the assumption of 100% oxygen utilization at the combustion front. Crookston et al. describe a linearized implicit combustion model that can describe the reaction of a predetermined set of gases and oils. Both of these models are predetermined set of gases and oils. Both of these models are multidimensional and do not handle wellbore-reservoir coupling fully implicitly. Rubin and Vinsome describe a fully implicit one-dimensional (ID) combustion tube simulator. Coats 4 describes a fully implicit four-phase multicomponent multidimensional combustion simulator. This model is general in nature except for the wellbore-reservoir coupling. This work describes a general, fully implicit, four-phase, multicomponent, multidimensional steam and combustion simulator that includes a fully implicit well model and a suite of powerful iterative techniques that can be used for the solution of large-scale thermal problems. The following sections of this paper describe the model's fluid and energy flow equations, property package, powerful iterative techniques capable of reliable package, powerful iterative techniques capable of reliable use with steam and combustion problems, fully implicit well model, and equation substitution formulation. Further, a section considering the applications of the model is presented. Mathematical Model The simulator ISCOM rigorously models fluid flow, vaporization/condensation phenomena, and heat transfer and is efficient enough to allow the simulation of realistically large reservoir problems. The formulation allows for any number of chemical components and reactions. The components can exist in any of four phases: oil, water, gas, or solid. A reaction also can occur in any of the above phases. Furthermore, water and any of the oil components can vaporize. The simulator development is based on the following assumptions.The model can operate in one, two, or three dimensions (1D, 2D, or 3D) with variable grid spacing.Cartesian, radial, non-Cartesian (variable-thickness grids), and specific curvilinear grids corresponding to the commonly used well patterns can be used. patterns can be used.The number of components existing in each phase is variable, and the components can be distributed among four phases.The number and type of chemical reactions can be varied.Each layer, well, or block in the reservoir can exhibit different properties (e.g., viscosities, relative permeabilities, and properties (e.g., viscosities, relative permeabilities, and compressibilities) at different times.Wells can operate under specified fluid rates or flowing pressures and are subject to a hierarchy of user-specified constraints.The simulator must be reasonably efficient to handle field-scale simulation economically, without sacrificing accuracy. Grid Generation The model defines a block-centered grid system in 1-, 2-, or 3D, normally based on Cartesian xyz coordinates. Radial geometries are accommodated by internal modification of the gridblock volumes and interblock transmissibilities. For rectangular grids with variable thickness layers, the interblock transmissibilities and gravity head terms are derived from gridblock dimensions and depth from reference. Curvilinear grids are generated by the method of conformal transformation, which yields analytical formulae for potential and stream functions. Two simple patterns are considered: one-eighth of a five-spot and one-eighth of a nine-spot. SPEJ P. 202

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Feo, Giuseppe, Jyotsna Sharma, and Stephen Cunningham. "Integrating Fiber Optic Data in Numerical Reservoir Simulation Using Intelligent Optimization Workflow." Sensors 20, no. 11 (May 29, 2020): 3075. http://dx.doi.org/10.3390/s20113075.

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A novel workflow is presented for integrating fiber optic Distributed Temperature Sensor (DTS) data in numerical simulation model for the Cyclic Steam Stimulation (CSS) process, using an intelligent optimization routine that automatically learns and improves from experience. As the steam–oil relationship is the main driver for forecasting and decision-making in thermal recovery operations, knowledge of downhole steam distribution across the well over time can optimize injection and production. This study uses actual field data from a CSS operation in a heavy oil field in California, and the value of integrating DTS in the history matching process is illustrated as it allows the steam distribution to be accurately estimated along the entire length of the well. The workflow enables the simultaneous history match of water, oil, and temperature profiles, while capturing the reservoir heterogeneity and the actual physics of the injection process, and ultimately reducing the uncertainty in the predictive models. A novel stepwise grid-refinement approach coupled with an evolutionary optimization algorithm was implemented to improve computational efficiency and predictive accuracy. DTS surveillance also made it possible to detect a thermal communication event due to steam channeling in real-time, and even assess the effectiveness of the remedial workover to resolve it, demonstrating the value of continuous fiber optic monitoring.

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Xie, Fangwei, Jinxin Cao, Erming Ding, Kuaidi Wan, Xinshi Yu, Jun Ke, and Kuidong Gao. "Temperature rise characteristics of the valve-controlled adjustable damping shock absorber." Mechanics & Industry 21, no. 1 (2020): 111. http://dx.doi.org/10.1051/meca/2019084.

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The thermodynamic study of the valve-controlled adjustable damping shock absorber is conducted in order to solve the problem of oil leakage caused by excessive temperature rise of shock absorber. In this paper, the temperature rise of the valve-controlled adjustable damping shock absorber is analyzed from the perspective of energy conservation. Combined with the theory of fluid mechanics, the damping heat model is established, and the heat dissipation model of the shock absorber is established based on heat convection, heat conduction and heat radiation. The corresponding thermal equilibrium equation is established on the basis of damping heat and heat dissipation. The effects of vibration velocity, outer diameter, thickness and length of reservoir cylinder, and wind velocity on its thermal performance have been investigated. Specifically, temperature after thermal equilibrium will grow with the increase of vibration velocity and thickness of reservoir cylinder and degrade with the increase of outer diameter, length of reservoir cylinder and wind velocity. The higher the balance temperature, the shorter time is required to arrive thermal equilibrium. The difference between the experimental and simulation values of oil temperature after thermal equilibrium was not more than 2 °C, which verified the correctness of the theoretical model, while the experimental value in the process of temperature rise lagged behind the simulation value, which was mainly caused by the cumulative error of step-by-step iteration and the mechanical hysteresis in the experiment. The conclusions obtained can provide some references for the design of shock absorbers.

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Journal articles on the topic 'Thermal reservoir simulation'

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