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Gutierrez, M., R. W. Lewis, and I. Masters. "Petroleum Reservoir Simulation Coupling Fluid Flow and Geomechanics." SPE Reservoir Evaluation & Engineering 4, no. 03 (June 1, 2001): 164–72. http://dx.doi.org/10.2118/72095-pa.
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Summary This paper presents a discussion of the issues related to the interaction between rock deformation and multiphase fluid flow behavior in hydrocarbon reservoirs. Pore-pressure and temperature changes resulting from production and fluid injection can induce rock deformations, which should be accounted for in reservoir modeling. Deformation can affect the permeability and pore compressibility of the reservoir rock. In turn, the pore pressures will vary owing to changes in the pore volume. This paper presents the formulation of Biot's equations for multiphase fluid flow in deformable porous media. Based on this formulation, it is argued that rock deformation and multiphase fluid flow are fully coupled processes that should be accounted for simultaneously, and can only be decoupled for predefined simple loading conditions. In general, it is shown that reservoir simulators neglect or simplify important geomechanical aspects that can impact reservoir productivity. This is attributed to the fact that the only rock mechanical parameter involved in reservoir simulations is pore compressibility. This parameter is shown to be insufficient in representing aspects of rock behavior such as stress-path dependency and dilatancy, which require a full tensorial constitutive relation. Furthermore, the pore-pressure changes caused by the applied loads from nonpay rock and the influence of nonpay rock on reservoir deformability cannot be accounted for simply by adjusting the pore compressibility. Introduction In the last two decades, there has been a strong emphasis on the importance of geomechanics in several petroleum engineering activities such as drilling, borehole stability, hydraulic fracturing, and production-induced compaction and subsidence. In these areas, in-situ stresses and rock deformations, in addition to fluid-flow behavior, are key parameters. The interaction between geomechanics and multiphase fluid flow is widely recognized in hydraulic fracturing. For instance, Advani et al.1 and Settari et al.2 have shown the importance of fracture-induced in-situ stress changes and deformations on reservoir behavior and how hydraulic fracturing can be coupled with reservoir simulators. However, in other applications, geomechanics, if not entirely neglected, is still treated as a separate aspect from multiphase fluid flow. By treating the two fields as separate issues, the tendency for each field is to simplify and make approximate assumptions for the other field. This is expected because of the complexity of treating geomechanics and multiphase fluid flow as coupled processes. Recently, there has been a growing interest in the importance of geomechanics in reservoir simulation, particularly in the case of heavy oil or bituminous sand reservoirs,3,4 water injection in fractured and heterogeneous reservoirs,5–7 and compacting and subsiding fields.8,9 Several approaches have been proposed to implement geomechanical effects into reservoir simulation. The approaches differ on the elements of geomechanics that should be implemented and the degree to which these elements are coupled to multiphase fluid flow. The objective of this paper is to illustrate the importance of geomechanics on multiphase flow behavior in hydrocarbon reservoirs. An extension of Biot's theory10 for 3D consolidation in porous media to multiphase fluids, which was proposed by Lewis and Sukirman,11 will be reviewed and used to clarify the issues involved in coupling fluid flow and rock deformation in reservoir simulators. It will be shown that for reservoirs with relatively deformable rock, fluid flow and reservoir deformation are fully coupled processes, and that such coupled behaviors cannot be represented sufficiently by a pore-compressibility parameter alone, as is done in reservoir simulators. The finite-element implementation of the fully coupled equations and the application of the finite-element models to an example problem are presented to illustrate the importance of coupling rock deformation and fluid flow. Multiphase Fluid Flow in Deformable Porous Media Fig. 1 illustrates the main parameters involved in the flow of multiphase fluids in deformable porous media and how these parameters ideally interact. The main quantities required to predict fluid movement and productivity in a reservoir are the fluid pressures (and temperatures, in case of nonisothermal problems). Fluid pressures also partly carry the loads, which are transmitted by the surrounding rock (particularly the overburden) to the reservoir. A change in fluid pressure will change the effective stresses following Terzaghi's12 effective stress principle and cause the reservoir rock to deform (additional deformations are induced by temperature changes in nonisothermal problems). These interactions suggest two types of fluid flow and rock deformation coupling:Stress-permeability coupling, where the changes in pore structure caused by rock deformation affect permeability and fluid flow.Deformation-fluid pressure coupling, where the rock deformation affects fluid pressure and vice versa. The nature of these couplings, specifically the second type, are discussed in detail in the next section. Stress-Permeability Coupling This type of coupling is one where stress changes modify the pore structure and the permeability of the reservoir rock. A common approach is to assume that the permeability is dependent on porosity, as in the Carman-Kozeny relation commonly used in basin simulators. Because porosity is dependent on effective stresses, permeability is effectively stress-dependent. Another important effect, in addition to the change in the magnitude of permeability, is on the change in directionality of fluid flow. This is the case for rocks with anisotropic permeabilities, where the full permeability tensor can be modified by the deformation of the rock. Examples of stress-dependent reservoir modeling are given by Koutsabeloulis et al.6 and Gutierrez and Makurat.7 In both examples, the main aim of the coupling is to account for the effects of in-situ stress changes on fractured reservoir rock permeability, which in turn affect the fluid pressures and the stress field. The motivation for the model comes from the field studies done by Heffer et al.5 showing that there is a strong correlation between the orientation of the principal in-situ stresses with the directionality of flow in fractured reservoirs during water injection. There is also growing evidence that the earth's crust is generally in a metastable state, where most faults and fractures are critically stressed and are on the verge of further slip.13 This situation will broaden the range of cases with strong potential for coupling of fluid flow and deformation.
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Siripatrachai, Nithiwat, Turgay Ertekin, and Russell T. Johns. "Compositional Simulation of Hydraulically Fractured Tight Formation Considering the Effect of Capillary Pressure on Phase Behavior." SPE Journal 22, no. 04 (March 6, 2017): 1046–63. http://dx.doi.org/10.2118/179660-pa.
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Summary Compositional reservoir simulation plays a vital role in the development of conventional and unconventional reservoirs. Two major building blocks of compositional simulation are phase-behavior and fluid-transport computations. The oil and gas reserves and flow of reservoir fluids are strongly dependent on phase behavior. In conventional reservoirs, capillary pressure is relatively small and is typically ignored in phase-behavior calculations. The approach is accepted as the norm to perform phase-equilibria calculation to estimate the oil and gas in place and fluid properties. However, large capillary pressure values are encountered in tight formations, such as shales, and therefore, its effects should not be ignored in phase-equilibria calculations. Many parameters and uncertainties contribute to the accuracy of the estimation and simulation results. In this research, the focus is on the effect of capillary pressure, and neglecting the effects of capillary pressure on phase behavior can lead to an inaccurate estimation of original oil in place (OOIP) and original gas in place (OGIP) as well as recovery performance because of the inherent assumption of equal phase pressures in the phase-equilibria calculation. Understanding of the effect of capillary pressure on phase behavior in tight reservoirs is by no means complete, especially by use of compositional simulation for hydraulically fractured reservoirs. In this paper, we develop a new compositional reservoir simulator capable of modeling discrete fractures and incorporating the effect of capillary pressure on phase behavior. Large-scale natural and hydraulic fractures in tight rocks and shales are modeled with a technique called the embedded-discrete-fracture model (EDFM), where fractures are modeled explicitly without use of local-grid refinement (LGR) or an unstructured grid. Flow of hydrocarbons occurs simultaneously within similar and different porosity types. Capillary pressure is considered in both flow and flash calculations, where simulations also include variable pore size as a function of gas saturation to accurately reflect temporal changes in each gridblock during the simulation. We examine the effect of capillary pressure on the OOIP and cumulative oil production for different initial reservoir pressures (above and below the bubblepoint pressure) on Bakken and Eagle Ford fluids. The importance of capillary pressure on both flow and flash calculations from hydraulically fractured horizontal wells during primary depletion in fractured tight reservoirs by use of two fluid compositions is demonstrated. Phase-behavior calculations show that bubblepoint pressure is suppressed, allowing the production to remain in the single-phase region for a longer period of time and also altering phase compositions and fluid properties, such as density and viscosity of equilibrium liquid and vapor. The results show that bubblepoint suppression is larger in the Eagle Ford shale than for Bakken. On the basis of the reservoir fluid and model used for the Bakken and Eagle Ford formations, when capillary pressure is included in the flash, we found an increase in OOIP up to 4.1% for the Bakken crude corresponding to an initial reservoir pressure of 2,000 psia and 46.33% for the Eagle Ford crude corresponding to an initial pressure of 900 psia. Depending on the initial reservoir pressure, cumulative primary oil production after 1 year increases because of the capillary pressure by approximately 9.0 to 38.2% for an initial reservoir-pressure range from 2,000 to 3,500 psia for Bakken oil and 7.2 to 154% for an initial reservoir-pressure range from 1,500 to 3,500 psia for Eagle Ford oil. The recovery increase caused by capillary pressure becomes more significant when reservoir pressure is far less than bubblepoint pressure. The simulation results with hydraulically fractured wells give similar recovery differences. For the two different reservoir settings in this study, at initial reservoir pressure of 5,500 psia, cumulative oil production after 1 year is 3.5 to 5.2% greater when capillary pressure is considered in phase-behavior calculations for Bakken. As initial reservoir pressure is lowered to 2,500 psia, the increase caused by capillary pressure is up to 28.1% for Bakken oil for the case studied. Similarly, at initial reservoir pressure of 2,000 psia, the increase caused by capillary pressure is 21.8% for Eagle Ford oil.
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Li, Hangyu, and Louis J. Durlofsky. "Upscaling for Compositional Reservoir Simulation." SPE Journal 21, no. 03 (June 15, 2016): 0873–87. http://dx.doi.org/10.2118/173212-pa.
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Summary Compositional flow simulation, which is required for modeling enhanced-oil-recovery (EOR) operations, can be very expensive computationally, particularly when the geological model is highly resolved. It is therefore difficult to apply computational procedures that require large numbers of flow simulations, such as optimization, for EOR processes. In this paper, we develop an accurate and robust upscaling procedure for oil/gas compositional flow simulation. The method requires a global fine-scale compositional simulation, from which we compute the required upscaled parameters and functions associated with each coarse-scale interface or wellblock. These include coarse-scale transmissibilities, upscaled relative permeability functions, and so-called α-factors, which act to capture component flow rates in the oil and gas phases. Specialized near-well treatments for both injection and production wells are introduced. An iterative procedure for optimizing the α-factors is incorporated to further improve coarse-model accuracy. The upscaling methodology is applied to two example cases, a 2D model with eight components and a 3D model with four components, with flow in both cases driven by wells arranged in a five-spot pattern. Numerical results demonstrate that the global compositional upscaling procedure consistently provides very accurate coarse results for both phase and component production rates, at both the field and well level. The robustness of the compositionally upscaled models is assessed by simulating cases with time-varying well bottomhole pressures that are significantly different from those used when the coarse model was constructed. The coarse models are shown to provide accurate predictions in these tests, indicating that the upscaled model is robust with respect to well settings. This suggests that one can use upscaled models generated from our procedure to mitigate computational demands in important applications such as well-control optimization.
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Behie, A., D. Collins, P. A. Forsyth, and P. H. Sammon. "Fully Coupled Multiblock Wells in Oil Simulation." Society of Petroleum Engineers Journal 25, no. 04 (August 1, 1985): 535–42. http://dx.doi.org/10.2118/11877-pa.
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Abstract A fully coupled treatment of oil wells that are completed in more than one zone results in a bordered matrix. This paper develops solution algorithms that incorporate paper develops solution algorithms that incorporate existing direct and iterative (incomplete LU) solutions in a straightforward manner. Timings in scalar and vector modes on the Cray for a typical reservoir simulation problem are presented. problem are presented. Introduction Numerical simulation of oil reservoirs requires the solution of coupled sets of highly nonlinear partial differential equations. These equations represent the conservation of oil, gas, water, and energy. It usually is necessary to solve from 3 to 10 coupled equations per finite-difference cell. The equations usually are discretized by use of a nearest-neighbor coupling in space and a fully implicit timestep scheme. The resulting set of nonlinear algebraic equations then is solved by Newtonian iteration., Clearly, simulation of large systems requires effective solution of the Jacobian matrix. Many practical reservoir simulation problems involve multiblock wells or fractures. These situations arise when a well is completed in several layers, and consequently the wellbore penetrates several finite-difference cells. Each conservation equation in a cell penetrated by a well will have a source term of the form .....................................(1) where qjt is the mass influx of component k (resulting from the well), Xk is the mobility of component k, 1 pi is the pressure in cell i, and pi, is the unknown wellbore pressure in well j. pressure in well j. To specify the wellbore pressure, pi, an additional equation is required. This extra equation as generally a constraint op the total flow into the well - This constraint is of the form .....................................(2) where qJt. is the total specified fluid flow into well j, Nc, is the total number of components, and is the set of cell numbers penetrated by well j. Because several cells are connected to the same well, there is now an extra degree of coupling between these cells through the well-bore pressure. This coupling generally will not be consistent with the coupling produced by the usual finite-difference molecule. If the well pressures, pjw, are treated explicitly, or are lagged one iteration, convergence difficulties or stability limitations often result. 7 Fully coupled treatment of multiblock wells gives rise to a bordered matrix. We develop various methods to solve these systems. These methods are specifically designed for the block-banded systems arising from fully implicit thermal problems, although similar methods can be used for single-component systems The iterative methods are extensions of the incomplete factorization techniques (ILU), and a direct method is presented for comparison. Existing solution routines can be modified easily to solve the bordered system. Solution of the Bordered Matrix The standard approach to solving fully implicit, fully coupled multiblock wells (or fractures) is to order the unknowns so that those connected with flow in the reservoir (cell pressures, saturations, etc.) appear first in the solution vector. The unknowns connected with the well (well pressures) are placed last in the solution vector. This produces a bordered Jacobian matrix (see Fig. 1). The upper left portion of the matrix has the usual incidence matrix for the Jacobian of nearest-neighbor finite-difference discretization. The incidence matrix for the Jacobian is a matrix with entries zero if the Jacobian elements are zero, and with entries one if the Jacobian elements are nonzero. The border of columns on the upper right of Fig. 1 contains derivatives of the source terms (Eq. 1) with respect to the wellbore pressure The border of rows on the lower left contains derivatives of the constraint equations (Eq. 2) with respect to reservoir variables (i.e., cell pressures). The block on the lower right contains derivatives of the constraint equations with respect to the wellbore pressures and is diagonal. The number of extra columns and rows is proportional to the number of fully coupled wells (or fractures). Although the incidence matrix of the reservoir flow portion of the matrix is symmetric, the incidence matrix of portion of the matrix is symmetric, the incidence matrix of the borders is not necessarily symmetric. George discusses three possible block factorizations of sparse, linear systems. The algorithm used here is based on his second factorization. SPEJ P. 535
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Saira and Furqan Le-Hussain. "Improving CO2 storage and oil recovery by injecting alcohol-treated CO2." APPEA Journal 60, no. 2 (2020): 662. http://dx.doi.org/10.1071/aj19145.
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Oil recovery and CO2 storage related to CO2 enhance oil recovery are dependent on CO2 miscibility. In case of a depleted oil reservoir, reservoir pressure is not sufficient to achieve miscible or near-miscible condition. This extended abstract presents numerical studies to delineate the effect of alcohol-treated CO2 injection on enhancing miscibility, CO2 storage and oil recovery at immiscible and near-miscible conditions. A compositional reservoir simulator from Computer Modelling Group Ltd. was used to examine the effect of alcohol-treated CO2 on the recovery mechanism. A SPE-5 3D model was used to simulate oil recovery and CO2 storage at field scale for two sets of fluid pairs: (1) pure CO2 and decane and (2) alcohol-treated CO2 and decane. Alcohol-treated CO2 consisted of a mixture of 4 wt% of ethanol and 96 wt% of CO2. All simulations were run at constant temperature (70°C), whereas pressures were determined using a pressure-volume-temperature simulator for immiscible (1400 psi) and near-miscible (1780 psi) conditions. Simulation results reveal that alcohol-treated CO2 injection is found superior to pure CO2 injection in oil recovery (5–9%) and CO2 storage efficiency (4–6%). It shows that alcohol-treated CO2 improves CO2 sweep efficiency. However, improvement in sweep efficiency with alcohol-treated CO2 is more pronounced at higher pressures, whereas improvement in displacement efficiency is more pronounced at lower pressures. The proposed methodology has potential to enhance the feasibility of CO2 sequestration in depleted oil reservoirs and improve both displacement and sweep efficiency of CO2.
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Mei, Fu Liang, and Gui Ling Li. "Increment-Dimensional Precise Integration Method of Oil-Water Coupling Flows in a Low Permeability Reservoir with Capillary Pressure." Applied Mechanics and Materials 580-583 (July 2014): 2883–89. http://dx.doi.org/10.4028/www.scientific.net/amm.580-583.2883.
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The simulation of two-phase oil-water coupling flows in a low permeability reservoir with capillary pressure and start-up pressure gradient was carried out. First of all, the state equations with all the oil pressures at grid nodes were established based on lump-centre finite difference method. Secondly, the recurrence formulae of all the oil pressures and water saturations at grid nodes were built up according to IDPIM and an explicit difference method, respectively. Finally, the simulation of two-phase oil-water coupling flows for a typical five point area water injection as an example was carried out. Simulating results show that capillary pressure has a little effect on moisture rate and oil production, but startup pressure gradients have an outstanding effect on them. Therefore the existence of startup pressure gradients will enhance the difficulty of oil development.
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Wang, Yi, Bo Yu, and Ye Wang. "Acceleration of Gas Reservoir Simulation Using Proper Orthogonal Decomposition." Geofluids 2018 (2018): 1–15. http://dx.doi.org/10.1155/2018/8482352.
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High-precision and high-speed reservoir simulation is important in engineering. Proper orthogonal decomposition (POD) is introduced to accelerate the reservoir simulation of gas flow in single-continuum porous media via establishing a reduced-order model by POD combined with Galerkin projection. Determination of the optimal mode number in the reduced-order model is discussed to ensure high-precision reconstruction with large acceleration. The typical POD model can achieve high precision for both ideal gas and real gas using only 10 POD modes. However, acceleration of computation can only be achieved for ideal gas. The obstacle of POD acceleration for real gas is that the computational time is mainly occupied by the equation of state (EOS). An approximation method is proposed to largely promote the computational speed of the POD model for real gas flow without decreasing the precision. The improved POD model shows much higher acceleration of computation with high precision for different reservoirs and different pressures. It is confirmed that the acceleration of the real gas reservoir simulation should use the approximation method instead of the computation of EOS.
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Muneta, Yasuhiro, Magdi I. Mubarak, Hadi H. Alhasani, and Kazuyoshi Arisaka. "Formulation of "Capillary Force Barriers" in Moderately-Oil Wet Systems and Its Application to Reservoir Simulation." SPE Reservoir Evaluation & Engineering 8, no. 05 (October 1, 2005): 388–96. http://dx.doi.org/10.2118/88711-pa.
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Summary As a common production aspect of the Thamama formation (a carbonate reservoir) in both onshore and offshore Abu Dhabi fields, unexpected early-water breakthrough through specific high-permeability layers without a clearly impermeable layer underneath has been observed in several water-injection schemes. Observed field data such as pulsed neutron capture(PNC) logs indicate the absence of injected water slumping away from wellbores. The concept of capillary force barriers was introduced a decade ago to resolve this issue, in which the role of capillary pressure forces on crossflow in stratified layers is modeled. This paper tries to revisit and fine-tune the concept of capillary force barrier and model hysteresis expected in a moderately oil-wet system. First, some measurements of special core analysis and related interpretations are presented in which the results are analytically formulated by a published methodology to generate saturation functions consistent with hysteresis using an assumption of wettability. An application of the formulation to numerical reservoir simulation was carried out in a systematic manner because the reservoir-rock-type (RRT) scheme of the model was based on primary-drainage curves that can be fully linked with the generated saturation functions. It is demonstrated on cross sections how small differences in imbibition capillary pressures can affect the water movement across contrasting RRT boundaries in a moderately oil-wet system. The proposed formulation is an effective tool for generalizing saturation functions related to matrix properties in a consistent manner, and it systematically incorporates hysteresis and wettability into the numerical reservoir-simulation model. Introduction Many giant carbonate reservoirs in the Middle East, including those of the Thamama formation in both onshore and offshore Abu Dhabi, are developed with water-injection schemes. These reservoirs typically exhibit oil-wet character;in such cases, the injected water does not slump, instead moving through thin, high-permeability layers. This has been considered as one of the key reasons for unexpected early water breakthrough to oil producers. To explain the phenomenon, the concept of capillary force barriers was introduced to model the role of negative imbibition capillary pressures in the water-displacement process for an oil-wet system. The concept, however, is difficult to apply to actual reservoir-simulation modeling because of the general heterogeneity of carbonate rocks and the difficulty in characterizing them in a systematic manner with due consideration of geological features. Meanwhile, numerous papers have described detailed measurements of special core analysis to emphasize the importance of some of the specific rock properties such as capillary pressure, relative permeability, wettability, and so on. However, the literature is sparse regarding the application of such measurements to field-scale reservoir-simulation modeling in an integrated manner, probably because of the data unavailability and the poor link with geological features, which is the most important guide to distributing the petrophysical parameters in numerical reservoir-simulation models. This paper develops a systematic scheme of saturation functions tied to rock-matrix properties for reservoir-simulation modeling. The targets of this work are as follows:• Analytical formulation of specific saturation functions, maintaining their consistency by linking them to pore-size distribution (PSD).• Understanding the mechanism of capillary force barriers in the formulation.• Incorporating wettability into reservoir simulation in a consistent manner. It is worth mentioning that for successful formulation of the saturation functions on reservoir-simulation modeling, consistent RRT schemes are essential. A concept of RRT contrast, therefore, is discussed.
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Liang, Jialing, and Barry Rubin. "A Semi-Implicit Approach for Integrated Reservoir and Surface-Network Simulation." SPE Reservoir Evaluation & Engineering 17, no. 04 (April 30, 2014): 559–71. http://dx.doi.org/10.2118/163615-pa.
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Summary Conventionally, methods of coupling reservoirs and surface networks are categorized into implicit and explicit approaches. The term "implicit coupling" indicates that the two simulators solve unknowns together, simultaneously, or iteratively, whereas "explicit coupling" indicates that the two simulators solve unknowns sequentially and exchange their boundary conditions at the last coupled time tn. The explicit approach is straightforward to implement in existing reservoir and surface-network models and is widely used. Explicit coupling does have drawbacks, however, because well rate and pressure oscillations are often observed. In this paper, a new semi-implicit method for coupled simulation is presented. This technique stabilizes and improves the accuracy of the coupled model. The "semi-implicit coupling" overcomes the problems found in explicit-coupling methods without requiring the complexity of a fully implicit coupled model. The new approach predicts inflow-performance-relationship (IPR) curves at the next coupled time tn+1 by simultaneously conducting well tests for all wells in the reservoir before actually taking the required timestep. All wells first flow simultaneously to the next coupled time tn+1 with the well rates unchanged from the last coupled timestep. The timestep is rewound, and all well rates are reduced by a uniform fraction and then simultaneously flow again to tn+1. By extrapolating the resulting well pressures, the well's shut-in pressures at time tn+1 are determined, and thus, straight-line IPRs are produced. The new IPR curves approximate better each well's drainage region at tn+1 and each well's shut-in pressure at tn+1 which helps to stabilize the explicitly coupled model. The new coupling technique normally does not require iteration between the reservoir and surface network and normally has the stability and accuracy characteristics of an implicitly coupled approach. Because the well tests already account for individual well-drainage regions, an explicit knowledge of the well-drainage region is not required. Because of the stabilized IPR, the approach also was found to reduce the overall computational time compared with explicit coupling. Applications of the new approach are presented that show significant improvements surpassing explicit coupling in both stability and accuracy.
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Mei, Fu Liang, Xiang Song Wu, and Guang Ping Lin. "Application of Increment-Dimension Precise Integration Method in Numerical Simulation of Two-Phase Oil-Water Flows in a Low Permeability Reservoir." Advanced Materials Research 243-249 (May 2011): 5985–88. http://dx.doi.org/10.4028/www.scientific.net/amr.243-249.5985.
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The numerical simulation of two-phase oil-water flows in a low permeability reservoir was carried out by means of an increment-dimension precise integration method (IDPIM). First of all, state equations denoted with pore fluid pressures at mesh nodes were built up according to finite difference method (FDM). Secondly, the recurrence formulae of the pore fluid pressures at mesh nodes were set up based on IDPIM. Finally, the numerical simulations of two-phase oil water seepages for a typical five point injection-production reservoir as an example were conducted by means of IDPIM and IMPES respectively. Calculation results by IDPIM are in good accordance with those by IMPES, and then IDPIM is quite reliable. At the same time, the effect rule of the startup pressure gradients on recovery degree, liquid production rate and oil production rate has been investigated. The start-up pressure gradients have an outstanding effect on recovery degree, liquid production rate and oil production rate, and the existence of the startup pressure gradients will enhance development difficulty and cost.
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Burachok, O. V., D. V. Pershyn, S. V. Matkivskyi, and O. R. Kondrat. "Evaluation of black-oil PVT-model applicability for simulation of gas-condensate reservoirs." Мінеральні ресурси України, no. 2 (August 19, 2020): 43–48. http://dx.doi.org/10.31996/mru.2020.2.43-48.
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Creation of geological and simulation models is the necessary condition for decision making towards current development status, planning of well interventions, field development planning and forecasting. In case of isothermal process, for proper phase behavior and phase transitions two key approaches are used: a) simplified model of non-volatile oil, so called “black oil” model, in which each phase – oil, water and gas, are represented by respective component, and solution to fiow equations is based on finding the saturations and pressures in each numerical cell, and change of reservoir fiuid properties is defined in table form as a function of pressure; b) compositional model, in which based on equation of state, phase equilibrium is calculated for hydrocarbon and non-hydrocarbon components, and during fiow calculations, apart from saturations and pressures, oil and gas mixture is brought to phase equilibrium, and material balance is calculated for each component in gas and liquid phase. To account for components volatility, the classic black oil model was improved by adding to the formulation gas solubility and vaporized oil content. This allows its application for the majority of oil and gas reservoirs, which are far from critical point and in which the phase transitions are insignificant. Due to smaller number of variables, numerical solution is simpler and faster. But, considering the importance and relevance of increasing the production of Ukrainian gas and optimization of gas-condensate fields development, the issue of simplified black oil PVT-model application for phase behavior characterization of gas-condensate reservoirs produced under natural depletion depending on the liquid hydrocarbon’s potential yield. Comparative study results on evaluation of production performance of synthetic reservoir for different synthetically-generated reservoir fiuids with different С5+ potential yield is provided as plots and tables. Based on the results the limit of simplified black oil PVT-model application and the moment of transition to compositional model for more precise results could be defined.
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Price, Neil, Paul LaPointe, Kevin Parmassar, Chunmei Shi, Phil Diamond, Aleta Finnila, and Ole Krogh Jensen. "Dynamic calibration of the Shaikan Jurassic full-field fractured reservoir model through single-well DST and multi-well interference discrete fracture network simulation." Journal of the Geological Society 177, no. 6 (June 15, 2020): 1294–314. http://dx.doi.org/10.1144/jgs2019-137.
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The hydraulic behaviour of the fractures in a fractured carbonate reservoir is a function of fracture intensity, aperture, intrinsic permeability, length, height and orientation, all of which influence the scale of connectivity and ultimately storage, productivity and reserves. If a geologically realistic fracture model is not appropriately incorporated into upscaled fracture properties for a dynamic simulation, it may still be possible to match a short production history, but calculations of field-wide fracture pore volumes and forecasts of future reservoir development may be poor and uncertain. To accurately represent the fractures, discrete fracture network (DFN) models were built and used to constrain fracture geometries and their hydraulic properties for use in forecasting, field development options and uncertainty characterization. The workflow illustrated in this paper shows how a DFN may be validated and calibrated through the simulation of transient bottom hole pressures from individual drill stem tests and pressure interference data, followed by upscaling to a full-field dynamic simulation model. This DFN-to-simulation workflow, applicable to most conventional fractured reservoirs, successfully matched reservoir pressure history for the field as a whole and for individual wells without having to locally modify any of the upscaled fracture properties around the wells. Sensitivity analysis identified key fracture drivers having the greatest impact upon the history match, and these were combined to produce history matched Low and High Case models. Production forecasts for the Low, Base and High Cases were used to predict reserves, manage risk and optimize the field development plan.Supplementary material: Supplementary figures are available at https://doi.org/10.6084/m9.figshare.c.5001203Thematic collection: This article is part of the The Geology of Fractured Reservoirs collection available at: https://www.lyellcollection.org/cc/the-geology-of-fractured-reservoirs
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Al-Abri, Abdullah, and Robert Amin. "Numerical simulation of CO2 injection into fractured gas condensate reservoirs." APPEA Journal 51, no. 2 (2011): 742. http://dx.doi.org/10.1071/aj10122.
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More than sixty percent of the world’s remaining oil reserves are hosted by intensely fractured porous rocks, such as the carbonate sequences of Iran, Iraq, Oman, or offshore Mexico (Bedoun, 2002). The high contrast of capillarity between the matrix and the fractures makes a significant difference in the recovery performance of fractured and non-fractured reservoirs (Lemonnier and Bourbiaux, 2010). Simulation of naturally fractured reservoirs is a challenging task from both a reservoir description and a numerical standpoint (Selley, 1998). This paper presents the recovery performance of CO2 injection into a local fractured and faulted gas condensate reservoir in Western Australia. Tempest 6.6 compositional simulation model was used to evaluate the performance of uncertain reservoir parameters, injection design variables, and economic recovery factors associated with CO2 injection. The model incorporates experimental IFT, relative permeability data and solubility data at various thermodynamic conditions for the same field. These measurements preceded the simulation work and are now published in various places. The model uses Todd-Longstaff mixing algorithm to control the displacement front expansion. This paper will present, with aid of simulation output graph and tornado charts, the results of natural depletion, miscible and immiscible CO2 injection, waterflooding, WAG, sensitivity of fracture porosity, permeability and fracture intensity. The results also demonstrate the effect of initial reservoir composition, well completion and injection flow rate. All simulation cases were carried out at various injection pressures. The results are discussed in terms of transport mechanisms and fluid dynamics. This project was sponsored by a consortium of companies.
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Lozynskyi, O. Ye, and V. O. Lozynskyi. "Geological-Field Simulation of the "Well – Formation" System for Low-permeable Reservoirs." Prospecting and Development of Oil and Gas Fields, no. 3(72) (September 30, 2019): 51–57. http://dx.doi.org/10.31471/1993-9973-2019-3(72)-51-57.
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The aim of the research is the creation of an algorithm and a computer program to study the feasibility of poor wells developing. The research method is hydrodynamic simulation of the “well – formation” system by studying the behavior of low-permeable oil-filled reservoirs in the process of creating rising overburdens on the formation (abnormal formation pressures). Geological factors limiting the productivity of an oil well are analyzed. The degree of the decrease of the negative effect of these factors on oil influx to the bottomhole is predicted. The authors have studied the possibility of creating supplementary filtering channels in the bottomhole zone and the possibility of increasing hydroconductivity of the exposed reservoirs within the maximum possible drainage area. The authors also suggest the method to study poor wells using multiple injection of fluid into the reservoir and a gradual increase of the injection pressure and the overburden on the formation. In order to simulate the bottomhole pressure drop in a multi-cycle study, the authors make an algorithm based on an equation linking the pressure at a certain time point after the well shut-in to record the pressure decline curve with an integrated indicator. This indicator takes into account the volume of injection of fluid into the reservoirs before the well shut-in, the total duration of the injection of fluid into the reservoirs, the duration of time from the beginning of the injection of fluid into the reservoirs till the end of the process and the coefficient of the reservoir conductivity at each research cycle. The developed algorithm and computer technology provide the accumulation, storage, processing and reproduction of objective geological-field information. This will give a possibility to make a grounded decision about taking measures to increase the influx of production to the wells. The final result of these measures will be the transfer of out-balance reserves in the drainage areas of the wells to balance reserves and an increase in the total oil production at the field.
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Liu, Kai, Daiyin Yin, and Yong Wang. "Pressure-Predicting Model for Ultralow-Permeability Reservoirs considering the Water Absorption Characteristics of Mudstone Formations." Geofluids 2020 (June 14, 2020): 1–13. http://dx.doi.org/10.1155/2020/6531254.
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The injection-production ratio of ultralow-permeability reservoirs is generally higher in the early stage of development because of the water absorption characteristics of transition layers and mudstone formations. In this paper, the water absorption characteristics of mudstone are experimentally studied, and the empirical function of the water absorption process is established. A new mathematical model of the whole lithology is established by applying the research results of mudstone water absorption characteristics. Combining the material balance method and finite difference method, the space terms in the basic differential equation are replaced by the material balance equation, and the finite difference in the time term is obtained. Then, the analytical solutions of the average pressures of the reservoir oil well area, reservoir water well area, transition layers, and mudstone formations are solved. Based on the static parameters of the reservoir in the Chaoyang Gou Oilfield of the ultralow-permeability reservoir in China, the new pressure prediction model is verified by the ideal model of numerical simulation and production data of the oil field. The experimental results show that the saturation water absorption rate of mudstone is 1.54-2.55%, and the water absorption process of mudstone cannot be described by the seepage equation of sandstone. The verification results of the numerical simulation show that the pressure of the transition layers and mudstone at the end of the water well gradually increases, while the pressure at the end of the oil well basically remains unchanged, which is consistent with the assumptions of the model. The verification results of the oilfield production data show that the water well static pressure and oil well static pressure calculated by the new model are highly consistent with the actual values, which well explains the phenomenon of the low reservoir pressure level under the condition of a high injection production ratio in an ultralow-permeability reservoir.
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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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Kalogeropoulos, Kleomenis, Nikolaos Stathopoulos, Athanasios Psarogiannis, Evangelos Pissias, Panagiota Louka, George P. Petropoulos, and Christos Chalkias. "An Integrated GIS-Hydro Modeling Methodology for Surface Runoff Exploitation via Small-Scale Reservoirs." Water 12, no. 11 (November 13, 2020): 3182. http://dx.doi.org/10.3390/w12113182.
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Efficient and sustainable exploitation of water resources requires the adoption of innovative and contemporary management techniques, a need that becomes even more demanding due to climate change and increasing pressures coming from anthropogenic activities. An important outcome of this reality is the qualitative and quantitative degradation of groundwater, which clearly indicates the need to exploit surface runoff. This study presents an integrated Geographic Information System (GIS)-based methodological framework for revealing and selecting suitable locations to build small-scale reservoirs and exploit surface runoff. In this framework, the SWAT model was used to quantify surface runoff, followed by the simulation of reservoir scenarios through reservoir simulation software. Andros Island (located in Cyclades Prefecture), Greece was selected as the study area. The obtained results indicated the most suitable location for creating a reservoir for maximizing exploitation of surface runoff, based on the specific water demands of the nearby areas and the existing meteorological, hydrological, and geological background potential. Thus, two selected dam locations are analyzed by using the proposed framework. The findings showed that the first dam site is inappropriate for creating a reservoir, as it cannot meet the demand for large water extraction volumes. In addition, the outcomes confirmed the efficiency of the proposed methodology in optimum selection of locations to construct small-scale water exploitation works. This research presents a contemporary methodological framework that highlights the capability of GIS, SWAT modeling, and reservoir simulation coupling in detecting optimal locations for constructing small reservoirs.
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Pringgana, Gede, and I. Gede Adi Susila. "Numerical modelling of tsunami bore impact on low-rise residential buildings using SPH." MATEC Web of Conferences 276 (2019): 01006. http://dx.doi.org/10.1051/matecconf/201927601006.
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The resilience of buildings subject to tsunami bore impact can be improved by reducing tsunami-induced lateral hydrodynamic pressure by allowing part of the tsunami bore to pass through the buildings via openings and break-away walls. This research investigated the reduction of lateral pressure caused by tsunami bore impact on a low-rise residential building with openings proposed as the prototype of tsunami-resistant house. Numerical method using smoothed particle hydrodynamic (SPH)- based software called DualSPHysics was used to create simulation in numerical boundary in the form of a water tank. The tsunami-like bore simulations were generated based on dam-break analogy and were validated against experimental results. Four simulation cases were conducted in this study: Case 1 and Case 2 were dealing with the parameter sensitivity of reservoir height and distance between reservoir and building, while Case 3 and Case 4 were related to the effectiveness of openings and the base elevation of building in reducing wave impact pressures. The numerical modelling results show that the presence of openings and building’s base elevation significantly reduced the lateral hydrodynamic pressures on buildings up to 50% and this could become an effective strategy for improving the resilience of low-rise residential buildings under tsunami bore impact.
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Ding, Yu, Gerard Renard, and Luce Weill. "Representation of Wells in Numerical Reservoir Simulation." SPE Reservoir Evaluation & Engineering 1, no. 01 (February 1, 1998): 18–23. http://dx.doi.org/10.2118/29123-pa.
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Summary In reservoir simulation, linear approximations generally are used for well modeling. However, these types of approximations can be inaccurate for fluid-flow calculation in the vicinity of wells, leading to incorrect well-performance predictions. To overcome such problems, a new well representation1 has been proposed that uses a "logarithmic" type of approximation for vertical wells. In this paper, we show how the new well model can be implemented easily in existing simulators through the conventional productivity index (PI). We discuss the relationship between wellbore pressure, wellblock pressure, and flow rate in more detail, especially for the definition of wellblock pressure. We present an extension of the new approach to off-center wells and to flexible grids. Through this extension, the equivalence of various gridding techniques for the well model is emphasized. The key element is the accurate calculation of flow components in the vicinity of wells. Introduction The well model plays an important role in reservoir simulation because the precision of calculation in well-production rate or bottomhole pressure is directly related to this well model. The main difficulty of well modeling is the problem of singularity because of the difference in scale between the small wellbore diameter (less than 0.3 m) and the large wellblock grid dimensions used in the simulation (from tens to hundreds of meters), and to the radial nature of the flow around the well (i.e., nonlinear but logarithmic variation of the pressure away from the well). Thus, the wellblock pressure calculated by standard finite-difference methods is not the wellbore pressure. Peaceman2,3 first demonstrated that wellblock pressure calculated by finite difference in a uniform grid corresponds to the pressure at an equivalent wellblock radius, r0, related to gridblock dimensions. Assuming a radial flow around the well, he demons-trated that this radius could be used to relate the wellblock pressure to the wellbore pressure. However, there are problems with this approach in many practical reservoir simulation studies:For routinely used nonuniform Cartesian grids,4 there is no easy means to determine an r0 value.In three-dimensional (3D) cases with non-fully-penetrating wells, the basic radial flow assumption does not apply,5 whereas vertical flow effects must be included.6Off-center wells are not correctly treated.7,8Treatment of the well model is much more complicated with non Cartesian or flexible grids.9–11 The aim of this paper is to show that the new well representation1 proposed in a previous paper can handle these problems accurately. Wellblock Pressure Calculation A previous paper1 presented a new approach particularly well-suited to nonuniform grids for the modeling of vertical wells in numerical simulation. The principle of this new approach, which is based on a finite-volume method, is to calculate new interblock distances that improve the modeling of flow in the vicinity of wells. Because the new approach was originally presented for two-dimensional (2D)-XY problems, it was shown that for such problems the wellbore pressure could be calculated without both the intermediate computation of the wellblock pressure and introduction of an equivalent wellblock radius. However, for at least two reasons, it is convenient to keep this standard method commonly used in numerical models, which consists of relating the wellbore pressure and wellblock pressure through the use of a numerical PI and equivalent wellblock radius. One reason is practical. To implement the new approach more easily into standard numerical models, it is better to keep their internal structure unchanged. The other reason is dictated by the necessity of having a wellblock pressure in particular 3D simulation studies. When a well partially penetrates the reservoir or when there is communication between different layers, there is a vertical flow component in the vicinity of the well that necessitates that the wellblock pressure be calculated. How should the new approach be implemented in standard reservoir simulators- In these simulators, a numerical PI is used in the well model to relate the wellbore pressure, pw, to the wellblock pressure, p0. Usually, this PI is written as where r0 is the equivalent wellblock radius at which the pressure is equal to p0. Within the new well representation,1 to obtain a pressure p0 corresponding to a radius r0, it is sufficient to use equivalent wellblock transmissibilities relating p0 to the pressures of adjacent blocks through equivalent interblock distances, Leq, i (Fig. 1: where ?x0, ?y0 are the wellblock dimensions. For instance, in the x+ direction, Leq,1 is written where ?1+2 arctg (?y0 /?x0) is the angle formed by the right wellblock interface seen from the well. Because wellblock transmissibilities in standard models are conventionally expressed by the new approach can be implemented easily in standard models multiplying the conventional wellblock transmissibilities by constant factors. For instance, in the x+ direction, this factor is By use of equivalent transmissibilities, the calculated wellblock pressure, p0, should correspond to the equivalent wellblock radius, r0, which is involved in transmissibility calculations (Eq. 3). Then, the wellblock pressure can be related to the wellbore pressure with the conventional PI (Eq. 1).
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Sugiyama, S., Y. Liang, S. Murata, T. Matsuoka, M. Morimoto, T. Ohata, M. Nakano, and E. S. Boek. "Construction, Validation, and Application of Digital Oil: Investigation of Asphaltene Association Toward Asphaltene-Precipitation Prediction." SPE Journal 23, no. 03 (February 6, 2018): 952–68. http://dx.doi.org/10.2118/189465-pa.
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Summary Digital oil, a realistic molecular model of crude oil for a target reservoir, opens a new door to understand properties of crude oil under a wide range of thermodynamic conditions. In this study, we constructed a digital oil to model a light crude oil using analytical experiments after separating the light crude oil into gas, light and heavy fractions, and asphaltenes. The gas and light fractions were analyzed by gas chromatography (GC), and 105 kinds of molecules, including normal alkanes, isoalkanes, naphthenes, alkylbenzenes, and polyaromatics (with a maximum of three aromatic rings), were directly identified. The heavy fraction and asphaltenes were analyzed by elemental analysis, molecular-weight (MW) measurement with gel-permeation chromatography (GPC), and hydrogen and carbon nuclear-magnetic-resonance (NMR) spectroscopy, and represented by the quantitative molecular-representation method, which provides a mixture model imitating distributions of the crude-oil sample. Because of the low weight concentration of asphaltenes in the light crude oil (approximately 0.1 wt%), the digital oil model was constructed by mixing the gas, light-, and heavy-fraction models. To confirm the validity of the digital oil, density and viscosity were calculated over a wide range of pressures at the reservoir temperature by molecular-dynamics (MD) simulations. Because only experimental data for the liquid phase were available, we predicted the liquid components of the digital oil at pressures lower than 16.3 MPa (i.e., the bubblepoint pressure) by flash calculation, and calculated the liquid density by MD simulation. The calculated densities coincided with the experimental values at all pressures in the range from 0.1 to 29.5 MPa. We calculated the viscosity of the liquid phase at the same pressures by two independent methods. The calculated viscosities were in good agreement with each other. Moreover, the viscosity change with pressure was consistent with the experimental data. As a step for application of digital oil to predict asphaltene-precipitation risk, we calculated dimerization free energy of asphaltenes (which we regarded as asphaltene self-association energy) in the digital oil at the reservoir condition, using MD simulation with the umbrella sampling method. The calculated value is consistent with reported values used in phase-equilibrium calculation. Digital oil is a powerful tool to help us understand mechanisms of molecular-scale phenomena in oil reservoirs and solve problems in the upstream and downstream petroleum industry.
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Minkoff, Susan E., C. Mike Stone, Steve Bryant, and Malgorzata Peszynska. "Coupled geomechanics and flow simulation for time‐lapse seismic modeling." GEOPHYSICS 69, no. 1 (January 2004): 200–211. http://dx.doi.org/10.1190/1.1649388.
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To accurately predict production in compactible reservoirs, we must use coupled models of fluid flow and mechanical deformation. Staggered‐in‐time loose coupling of flow and deformation via a high‐level numerical interface that repeatedly calls first flow and then mechanics allows us to leverage the decades of work put into individual flow and mechanics simulators while still capturing realistic coupled physics. These two processes are often naturally modeled using different time stepping schemes and different spatial grids—flow should only model the reservoir, whereas mechanics requires a grid that extends to the earth's surface for overburden loading and may extend further than the reservoir in the lateral directions. Although spatial and temporal variability between flow and mechanics can be difficult to accommodate with full coupling, it is easily handled via loose coupling. We calculate the total stress by adding pore pressures to the effective rock stress. In turn, changes in volume strain induce updates to porosity and permeability and, hence, dynamically alter the flow solution during simulation. Incorporating the resulting time‐dependent pressures, saturations, and porosities (from coupled flow and mechanics) into Gassmann's equations results in seismic wave velocities and densities that can differ markedly from those calculated from flow alone. In a synthetic numerical experiment based on Belridge field, California, incorporation of coupled flow and mechanical deformation into time‐lapse calculations produces compressional wave velocities that differ markedly from those produced by flow alone. In fact, it is the closing of the pores themselves (reduction in permeability) in this example which has the greatest impact on fluid pressures and saturations and, hence, elastic wave parameters such as velocity.
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Mohamed, Islam A., Adel Othman, and Mohamed Fathy. "A new approach to improve reservoir modeling via machine learning." Leading Edge 39, no. 3 (March 2020): 170–75. http://dx.doi.org/10.1190/tle39030170.1.
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In highly heterogeneous basins with complex subsurface geology, such as the Nile Delta Basin, accurate prediction of reservoir modeling has been a challenge. Reservoir modeling is a continuous process that begins with field discovery and ends with the last phases of production and abandonment. Currently, the stochastic reservoir modeling method is widely used instead of the traditional deterministic modeling method to consider spatial statistics and uncertainties. However, the modeling workflow is demanding and slow, typically requiring months from the initial model concept to flow simulation. In addition, errors from early model stages become cumulative and are difficult to change retroactively. To overcome these limitations, a new workflow is proposed that implements probabilistic neural network inversion to predict reservoir properties. First, well-log data were conditioned properly to match the seismic data scale. Then, the networks were trained and validated, using the conditioned well-log data and seismic internal/external attributes, to predict water saturation and effective porosity 3D volumes. The resulting volumes were sampled in simulation 3D grids and tested using a blind well test. Subsequently, the permeability was calculated from a porosity-permeability relationship inside the reservoir. Finally, a dynamic simulation project of the field was performed in which the historical field production and pressures were compared to the predicted values. One of the Pliocene deepwater turbidite reservoirs in the offshore Nile Delta was used to demonstrate the proposed approach. The results proved the accuracy of the model in predicting the reservoir properties and honoring the heterogeneity of the reservoir. The new approach represents a shortcut for the seismic-to-simulation process, providing a reliable and fast way of constructing a reservoir model and making the seismic-to-simulation process easier.
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Raziperchikolaee, Samin, and Srikanta Mishra. "Application of a physics-based lumped parameter model to evaluate reservoir parameters during CO2 storage." Journal of Petroleum Exploration and Production Technology 10, no. 8 (August 14, 2020): 3925–35. http://dx.doi.org/10.1007/s13202-020-00978-2.
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Abstract Evaluating reservoir performance could be challenging, especially when available data are only limited to pressures and rates from oil field production and/or injection wells. Numerical simulation is a typical approach to estimate reservoir properties using the history match process by reconciling field observations and model predictions. Performing numerical simulations can be computationally expensive by considering a large number of grids required to capture the spatial variation in geological properties, detailed structural complexity of the reservoir, and numerical time steps to cover different periods of oil recovery. In this work, a simplified physics-based model is used to estimate specific reservoir parameters during CO2 storage into a depleted oil reservoir. The governing equation is based on the integrated capacitance resistance model algorithm. A multivariate linear regression method is used for estimating reservoir parameters (injectivity index and compressibility). Synthetic scenarios were generated using a multiphase flow numerical simulator. Then, the results of the simplified physics-based model in terms of the estimated fluid compressibility were compared against the simulation results. CO2 injection data including bottom hole pressure and injection rate were also gathered from a depleted oil reef in Michigan Basin. A field application of the simplified physics-based model was presented to estimate above-mentioned parameters for the case of CO2 storage in a depleted oil reservoir in Michigan Basin. The results of this work show that this simple lumped parameter model can be used for a quick estimation of the specific reservoir parameters and its changes over the CO2 injection period.
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Lu, Yangfan, Hassan Bahrami, Mofazzal Hossain, Ahmad Jamili, Arshad Ahmed, and Chaolang Qiu. "Lowering the phase-trap damage in tight-gas reservoirs by using interfacial tension (IFT) reducers." APPEA Journal 53, no. 1 (2013): 363. http://dx.doi.org/10.1071/aj12031.
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Tight-gas reservoirs have low permeability and significant damage. When drilling the tight formations, wellbore liquid invades the formation and increases water saturation of the near wellbore area and significantly deceases permeability of this area. Because of the invasion, the permeability of the invasion zone near the wellbore in tight-gas formations significantly decreases. This damage is mainly controlled by wettability and capillary pressure (Pc). One of the methods to improve productivity of tight-gas reservoirs is to reduce IFT between formation gas and invaded water to remove phase trapping. The invasion of wellbore liquid into tight formations can damage permeability controlled by Pc and relative permeability curves. In the case of drilling by using a water-based mud, tight formations are sensitive to the invasion damage due to the high-critical water saturation and capillary pressures. Reducing the Pc is an effective way to increase the well productivity. Using the IFT reducers, Pc effect is reduced and trapped phase can be recovered; therefore, productivity of the TGS reservoirs can be increased significantly. This study focuses on reducing phase-trapping damage in tight reservoirs by using reservoir simulation to examine the methods, such use of IFT reducers in water-based-drilled tight formations that can reduce Pc effect. The Pc and relative permeability curves are corrected based on the reduced IFT; they are then input to the reservoir simulation model to quantitatively understand how IFT reducers can help improve productivity of tight reservoirs.
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Tawfeeq, Yahya Jirjees. "Mathematical modeling and numerical simulation of porous media single-phase fluid flow problem: a scientific review." International research journal of engineering, IT & scientific research 6, no. 4 (July 9, 2020): 15–28. http://dx.doi.org/10.21744/irjeis.v6n4.955.
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The complexity of porous media makes the classical methods used to study hydrocarbon reservoirs inaccurate and insufficient to predict the performance and behavior of the reservoir. Recently, fluid flow simulation and modeling used to decrease the risks in the decision of the evaluation of the reservoir and achieve the best possible economic feasibility. This study deals with a brief review of the fundamental equations required to simulate fluid flow through porous media. In this study, we review the derivative of partial differential equations governing the fluid flow through pores media. The physical interpretation of partial differential equations (especially the pressures diffusive nature) and discretization with finite differences are studied. We restricted theoretic research to slightly compressible fluids, single-phase flow through porous media, and these are sufficient to show various typical aspects of subsurface flow numerical simulation. Moreover, only spatial and time discretization with finite differences will be considered. In this study, a mathematical model is formulated to express single-phase fluid flow in a one-dimensional porous medium. The formulated mathematical model is a partial differential equation of pressure change concerning distance and time. Then this mathematical model converted into a numerical model using the finite differences method.
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Makimura, Dai, Makoto Kunieda, Yunfeng Liang, Toshifumi Matsuoka, Satoru Takahashi, and Hiroshi Okabe. "Application of Molecular Simulations to CO2-Enhanced Oil Recovery: Phase Equilibria and Interfacial Phenomena." SPE Journal 18, no. 02 (January 7, 2013): 319–30. http://dx.doi.org/10.2118/163099-pa.
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Summary Molecular simulation is a powerful technique for obtaining thermodynamic properties of a system of given composition at a specific temperature and pressure, and it enables us to visualize microscopic phenomena. In this work, we used simulations to study interfacial phenomena and phase equilibria, which are important to CO2-enhanced oil recovery (EOR). We conducted molecular dynamics (MD) simulation of an oil/water interface in the presence of CO2. It was found that CO2 was enriched at the interfacial region under all thermal conditions. Whereas the oil/water interfacial tension (IFT) increases with pressure, CO2 reduces the IFT by approximately one-third at low pressure and one-half at higher pressure. Further analysis on the basis of our MD trajectories shows that the O=C=O bonds to the water with a “T-shaped” structure, which provides the mechanism for CO2 enrichment at the oil/water interface. The residual nonnegligible IFT at high pressures implies that the connate or injected water in a reservoir strongly influences the transport of CO2/oil solutes in that reservoir. We used Gibbs ensemble Monte Carlo (GEMC) simulation to compute phase equilibria and obtain ternary phase diagrams of such systems as CO2/n-butane/N2 and CO2/n-butane/n-decane. Simulating hydrocarbon fluids with a mixture of CO2 and N2 enables us to evaluate the effects of N2 impurity on CO2-EOR. It also enables us to study the phase behavior, which is routinely used to evaluate the minimum miscibility pressure (MMP). We chose these two systems because experimental data are available for them. Our calculated phase equilibria are in fair agreement with experiments. We also discuss possible ways to improve the predictive capability for CO2/hydrocarbon systems. GEMC and MD simulations of systems with heavier hydrocarbons are straightforward and enable us to combine molecular-level thinking with process considerations in CO2-EOR.
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Aavatsmark, Ivar. "Interpretation of well-cell pressures on hexagonal grids in numerical reservoir simulation." Computational Geosciences 20, no. 5 (May 19, 2016): 1029–42. http://dx.doi.org/10.1007/s10596-016-9575-2.
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Shade, Brandon C., Richard W. Melchior, Douglas R. Fisher, Robin High, Christopher E. Mascio, Tami M. Rosenthal, and David W. Holt. "Comparison of three infant venous reservoirs with vacuum-assisted venous drainage during varying levels of cardiotomy suction." Perfusion 35, no. 1 (May 31, 2019): 26–31. http://dx.doi.org/10.1177/0267659119850344.
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Background: Vacuum-assisted venous drainage has gained widespread use within the pediatric perfusion community for use during cardiopulmonary bypass. It is questioned whether its efficiency may be compromised with application of excessive cardiotomy suction to the infant hard-shell venous reservoir. An in vitro simulation circuit was used to research this phenomenon. A comparison of three different infant hard-shell venous reservoirs also took place to determine if one reservoir type was more advantageous when handling cardiotomy suction. The reservoirs tested were the Maquet VHK 11000, Medtronic Affinity Pixie, and Terumo Capiox FX05. Methods: The in vitro simulation circuit consisted of a 1 L reservoir bag that was cannulated at one access point with an Edwards Lifesciences 10Fr aortic cannula and the other access area with an Edwards Lifesciences 10Fr right angle venous cannula and 12Fr right angle venous cannula that were joined together. Key points of measurement and response variables were the pressures on the connection of the venous cannulas, inlet of the venous reservoir, and flow through the venous line. Vacuum was applied and manipulated with a Maquet VAVD Controller to settings of −20 mmHg, −30 mmHg, –40 mmHg, −50 mmHg, and −60 mmHg. Cardiotomy suction was added at settings of 1 LPM, 2 LPM, 3 LPM, and 4 LPM. Values from each response variable were monitored and recorded. These data were utilized to compare the reservoirs with a random coefficient model for each response variable. Conclusions: There is an adverse effect of excessive cardiotomy suction on the efficacy of vacuum-assisted venous drainage in infant hard-shell venous reservoirs. There is no significant difference between the VHK 11000, Pixie, and FX05 regarding their ability to handle this occurrence. An important discovery was that the FX05 showed a greater transfer of vacuum to the venous cannulas and reservoir inlet.
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Luo, Erhui, Zifei Fan, Yongle Hu, Lun Zhao, and Jianjun Wang. "An evaluation on mechanisms of miscibility development in acid gas injection for volatile oil reservoirs." Oil & Gas Science and Technology – Revue d’IFP Energies nouvelles 74 (2019): 59. http://dx.doi.org/10.2516/ogst/2019018.
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Produced gas containing the acid gas reinjection is one of the effective enhanced oil recovery methods, not only saving costs of disposing acid gases and zero discharge of greenhouse gases but also supporting reservoir pressure. The subsurface fluid from the Carboniferous carbonate reservoir in the southern margin of the Pre-Caspian basin in Central Asia has low density, low viscosity, high concentrations of H2S (15%) and CO2 (4%), high solution gas/oil ratio. The reservoir is lack of fresh water because of being far away onshore. Pilot test has already been implemented for the acid gas reinjection. Firstly, in our work a scheme of crude oil composition grouping with 15 compositions was presented on the basis of bottomhole sampling from DSTs of four wells. After matching PVT physical experiments including viscosity, density and gas/oil ratio and pressure–temperature (P–T) phase diagram by tuning critical properties of highly uncertain heavy components, the compositional model with phase behavior was built under meeting accuracy of phase fitting, which was used to evaluate mechanism of miscibility development in the acid gas injection process. Then using a cell-to-cell simulation method, vaporizing and/or condensing gas drive mechanisms were investigated for mixtures consisting of various proportions of CH4, CO2 and H2S in the gas injection process. Moreover, effects of gas compositions on miscible mechanisms have also been determined. With the aid of pressure-composition diagrams and pseudoternary diagrams generated from the Equation of State (EoS), pressures of First Contact Miscibility (FCM) and Multiple Contact Miscibility (MCM) for various gases mixing with the reservoir oil sample under reservoir temperature were calculated. Simulation results show that pressures of FCM are higher than those of MCM, and CO2 and H2S are able to reduce the miscible pressure. At the same time, H2S is stronger. As the CH4 content increases, both pressures of FCM and MCM are higher. But incremental values of MCM decrease. In addition, calculated envelopes of pseudoternary diagrams for mixtures of CH4, CO2 and H2S gases of varying composition with acid gas injection have features of bell shape, hourglass shape and triangle shape, which can be used to identify vaporizing and/or condensing gas drives. Finally, comparison of the real produced gas and the one deprived of its C3+ was performed to determine types of miscibility and calculate pressures of FCM and MCM. This study provides a theoretical guideline for selection of injection gas to improve miscibility and oil recovery.
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Riney, T. D. "Pleasant Bayou Geopressured-Geothermal Reservoir Analysis—October 1991." Journal of Energy Resources Technology 114, no. 4 (December 1, 1992): 315–22. http://dx.doi.org/10.1115/1.2905959.
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Many sedimentary basins contain formations with pore fluids at pressures higher than hydrostatic value; these formations are called geopressured. The pore pressure is generally well in excess of hydrostatic and the fluids are saline, hot, and contain dissolved methane. The U.S. Department of Energy (DOE) has drilled and tested deep wells in the Texas-Louisiana Gulf Coast region to evaluate the geopressured-geothermal resource. Geological information for the Pleasant Bayou geopressured resource in southeast Texas is most extensive among the reservoirs tested. Testing of the DOE well (Pleasant Bayou No. 2) was conducted during 1979–1983; testing resumed in May 1988. A numerical simulator is employed to synthesize and integrate the geological information, formation rock and fluid properties data from laboratory tests, and well data from the earlier (1979–1983) and the ongoing testing (1988–1991) of the well. A reservoir simulation model has been constructed which provides a detailed match to the well test history to date.
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Chen, Qing, Morten Kristensen, Yngve Bolstad Johansen, Vladislav Achourov, Soraya S. Betancourt, and Oliver Mullins. "Analysis of Lateral Fluid Gradients From DFA Measurements and Simulation of Reservoir Fluid Mixing Processes Over Geologic Time." Petrophysics – The SPWLA Journal of Formation Evaluation and Reservoir Description 62, no. 1 (February 1, 2021): 16–30. http://dx.doi.org/10.30632/pjv62n1-2021a1.
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Downhole fluid analysis (DFA) is one pillar of reservoir fluid geodynamics (RFG). DFA measurements provide both vertical and lateral fluid gradient data. These gradients, especially the asphaltene gradient derived from accurate optical density (OD) measurements, are critical in thermodynamic analysis to assess equilibration level and identify RFG processes. Recently, an RFG study was conducted using DFA and laboratory data from an oil field in the Norwegian North Sea. Fluid OD gradients show equilibrated asphaltenes in most of the reservoir, with a lateral variation of 20%. This indicates connectivity, which is confirmed by three years of production data. Two outliers are off the asphaltene equilibrium curve implying isolated sections, one each on the extreme east and west flank. Their asphaltene fraction varies by a factor of six. Such a difference reveals that different charge fluids entered the reservoir, and the equilibrated asphaltenes are the result of an after-charge mixing process. Meanwhile, different gas-oil contacts (GOCs) exist in the reservoir, indicating a lateral solution-gas gradient. Geochemistry analysis shows the same level of mild biodegradation in all the fluid samples, including those from two isolated sections. This means that biodegraded oil spills into the whole reservoir with little or no in-reservoir biodegradation. Furthermore, lateral asphaltene gradients at different times after charge have been preserved; it was a factor of six in asphaltenes content initially and is now 20% in the present day. This unique data set provides a valuable constraint to simulate reservoir fluid after-charge mixing processes to present day, aiming to investigate the factors impacting the evolution of lateral composition gradients in geologic time in a connected reservoir. Numerical simulations were performed over geologic time in reservoirs filled by oil with a lateral density gradient, which imitates the lateral compositional gradients in the gas-oil ratio (GOR) and asphaltenes measured in the above oil field. Simulations show that this lateral gradient creates lateral differential pressures and causes a countercurrent fluid flow forming a convection cell. In reservoirs with realistic vertical-to-horizontal aspect ratios, such fluid flows are not rapid, and lateral gradients can be partially retained in moderate geologic times. Additionally, diffusion was included in the simulation. The reservoir model was initialized with two GOCs producing subtle lateral GOR and density gradients. The simulated mixing process transports gas from higher GOR regions to lower GOR regions and reduces the GOC difference. However, the flux of solution gas transport is small. Consequently, we conclude that lateral GOR and asphaltene gradients can persist for moderate geologic time, which is consistent with observation from the field.
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Sun, Xiaohui, Youqiang Liao, Zhiyuan Wang, XinXin Zhao, and Baojiang Sun. "Modelling of Formation Pore Pressure Inversion during Tight Reservoir Drilling." Geofluids 2021 (February 3, 2021): 1–11. http://dx.doi.org/10.1155/2021/6626381.
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Identifying and controlling a kicking well hinge on quickly obtaining reliable and accurate formation pore pressure. In this study, we derive an analytical model for estimating formation pore pressure when a gas kick occurs during tight reservoir drilling. The model considers the variations in gas volume and pressures in the annulus affected by mutual coupling between the wellbore and formation, as well as bubble migration and expansion in the annulus. Additionally, a numerical computation method that reduces the effect of measurement noise using the Hooke-Jeeves algorithm is proposed. The method is capable of estimating pore pressure during the early stage of a kick in real time, is robust to the inherit noise of the measurements, and can be applied in scenarios when a well shut-in process cannot be performed. The simulation results demonstrate that both kick simulation and formation pore pressure inversion can be conducted via the proposed methodology. The errors of the pore pressure estimating results are less than 2.03% compared to the field data of seven wells. The method is tested and validated to be robust to noise and maintain good convergence performance, thereby providing drilling engineers with a simple and quick way to estimate pore pressure during a kick.
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Hassan, Omar F., and Dhefaf J. Sadiq. "New Correlation of Oil Compressibility at Pressures Below Bubble Point For Iraqi Crude Oil." Journal of Petroleum Research and Studies 1, no. 1 (May 5, 2021): 22–29. http://dx.doi.org/10.52716/jprs.v1i1.24.
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Oil compressibility represents a significant character in reservoir simulation, design of surface facilities and the analysis of well tests, specifically for systems below the bubble point pressure.
Oil compressibility is not directly measured in the laboratory. It is usually gained indirectly from experimental data recorded in PVT reports. The relative volume from the flash test is used to calculate oil compressibility at pressures above the bubble point pressure. At pressures below the bubble point, the reservoir behavior is simulated by the differential liberation test. The solution gas-oil ratio and the oil formation volume factor from the differential liberation test are employed in the estimation of oil compressibility at pressures below the bubble point pressure This paper purposes new correlation for calculating isothermal oil compressibility coefficient at and below bubble point pressure. The formulation of oil compressibility correlation is very difficult as it depends on many variables. This property is a function of many variables such as bubble point pressure, reservoir pressure, reservoir temperature, solution gas-oil ratio, oil formation volume factor, stock-tank oil gravity, specific gravity of gas and gas formation volume factor.
Standing’s (1), McCain et al. (2) and Al-Jarri's (3) correlations were submitted for testing their validity to evaluate their performance with Iraqi crude oils and to compare their results with the results of the new correlation.
The achievement of the new correlations has been done using two hundreds and nine data points from twenty PVT tests that were collected from Southern Iraqi fields. The evaluation of the previous correlations has achieved with graphical and statistical methods. These checking methods show a poor agreement between the observed and the calculated values.
The checking methods (graphical and statistical) explain that the new correlation that was achieved in this paper is suitable to calculate oil compressibility below bubble point pressure for Iraqi crude oils.
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Aavatsmark, Ivar. "Interpretation of well-cell pressures on stretched hexagonal grids in numerical reservoir simulation." Computational Geosciences 20, no. 5 (March 16, 2016): 1043–60. http://dx.doi.org/10.1007/s10596-016-9567-2.
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Shiralkar, G. S., R. E. Stephenson, Wayne Joubert, Olaf Lubeck, and Bart van Bloemen Waanders. "Falcon: A Production Quality Distributed Memory Reservoir Simulator." SPE Reservoir Evaluation & Engineering 1, no. 05 (October 1, 1998): 400–407. http://dx.doi.org/10.2118/51969-pa.
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This paper (SPE 51969) was revised for publication from paper SPE 37975, first presented at the 1997 SPE Reservoir Simulation Symposium, Dallas, 8-11 June. Original manuscript received for review 30 June 1997. Revised manuscript received 30 March 1998. Paper peer approved 6 July 1998. Summary We describe a new production model, Falcon, that has achieved speeds on parallel computers that are 100 times faster on real world problems than current production models on a vector computer. Falcon has been used to conduct the largest, geostatistical reservoir study ever conducted within Amoco. In this paper we discuss the following: Falcon's data parallel paradigm with FORTRAN 90 and high performance FORTRAN (HPF); its single program, multiple data (SPMD) paradigm with message passing; efficient memory management that enables simulation of enormous studies; a numerical formulation that reconciles the generalized compositional approach (based on component masses and pressure) with earlier approaches (based on pressures and saturations), in a more general and more efficient approach. We also discuss Falcon's scalability up to 512 processor nodes and performance (timings and memory) achieved on a number of parallel platforms, including Cray Research's T3D and T3E, SGI's Power Challenge and Origin 2000, Thinking Machines' CM5, and IBM's SP2. Falcon also runs on single processor computers such as PC's and IBM's RS6000. We discuss a new parallel linear solver technology based on a fully parallel scalable implementation of incomplete lower-upper (ILU) preconditioning coupled with a GMRES or Orthomin iteration process. This naturally ordered global ILU preconditioner is scalable to hundreds of processors, efficiently solving the matrix problems arising from large scale simulations. The use of the techniques described in this paper has enabled us to run problem sizes of up to 16.5 million gridblocks. Falcon was used to simulate fifty geostatistically derived realizations of a large, black oil waterflood system. The realizations, each with 2.3 million cells and 1,039 wells, took an average of 4.2 hours to execute on a 128-node CM5 computer, thus enabling the simulation study to finish in less than a month. In this field study, we bypassed upscaling through the use of fine vertical resolution gridding. Our focus has been on the applicability of Falcon to real world problems. Falcon can be used for modeling both small and very large reservoirs, including reservoirs characterized by geostatistics. It can be used to simulate black oil, gas/water, and dry gas reservoirs. And, a fully compositional feature is being developed. P. 400
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Hustad, Odd Steve, and David John Browning. "A Fully Coupled Three-Phase Model for Capillary Pressure and Relative Permeability for Implicit Compositional Reservoir Simulation." SPE Journal 15, no. 04 (July 27, 2010): 1003–19. http://dx.doi.org/10.2118/125429-pa.
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Summary A coupled formulation for three-phase capillary pressure and relative permeability for implicit compositional reservoir simulation is presented. The formulation incorporates primary, secondary, and tertiary saturation functions. Hysteresis and miscibility are applied simultaneously to both capillary pressure and relative permeability. Two alternative three-phase capillary pressure formulations are presented: the first as described by Hustad (2002) and the second that incorporates six representative two-phase capillary pressures in a saturation-weighting scheme. Consistency is ensured for all three two-phase boundary conditions through the application of two-phase data and normalized saturations. Simulation examples of water-alternating-gas (WAG) injection are presented for water-wet and mixed-wet saturation functions. 1D homogeneous and 2D and 3D heterogeneous examples are employed to demonstrate some model features and performance.
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Samier, Pierre, Atef Onaisi, and Sergio de Gennaro. "A Practical Iterative Scheme for Coupling Geomechanics With Reservoir Simulation." SPE Reservoir Evaluation & Engineering 11, no. 05 (October 1, 2008): 892–901. http://dx.doi.org/10.2118/107077-pa.
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Summary The use of reservoir simulation coupled with geomechanics has been increasing in recent years as its utility in modeling physical phenomena such as compaction, subsidence, induced fracturing, enhancement of natural fractures and/or fault activation, and steam-assisted gravity drainage (SAGD) recovery has become apparent. Among different methods investigated by researchers, the iterative explicit method appears to be the preferred method for field-scale simulation. This method is a loose coupled approach between a reservoir simulator and a geomechanical simulator. At user-defined steps, the fluid pressures are transmitted to the geomechanical tool, which computes the actual stresses and reports the modifications of porosities and permeabilities back to the reservoir simulator. This paper presents a new iterative scheme that allows any reservoir simulator to be coupled with any nonlinear finite-element-method (FEM) package for the stress analysis without any limitation on the functionality of either simulator. The convergence of this new scheme is discussed, and results are presented for three cases described below. The first case is a validation case used by other SPE papers. The second case is a synthetic model of a highly compacting reservoir sensitive to water saturation. The third case is a full-field reservoir model. Introduction The importance of geomechanics in problems such as wellbore stability, hydraulic fracturing, and subsidence is well known. In recent years, there has been growing awareness of the importance of the link between fluid flow and geomechanics in the management of stress-sensitive reservoirs (Chen and Teufel 2001; Gutierrez et al. 1994, 1995; Gutierrez and Lewis 1998; Osorio et al. 1999; Settari and Mourits 1998; Somerville and Smart 2000; Stone et al. 2000; Tran et al. 2002). New needs for coupled simulations appear, such as assessing the integrity of the overburden for heavy-oil recovery using thermal mechanisms (e.g., SAGD technique) or for acid-gas injection. Standard reservoir simulation of compaction drive accounts for nonlinear porosity changes determined from uniaxial-strain tests on cores. In many cases, laboratory-derived compressibility must be adjusted to match the contribution of compaction to total hydrocarbon recovery. Geomechanical effects such as stress arching and nonunique stress path are among the causes of discrepancy between laboratory-derived and field compressibility factors. If compressibility varies linearly with the mean reservoir pressure, then predictive reservoir modeling can be achieved without coupling between stress and flow. However, geomechanical effects are rarely linear, for a number of reasons. These include load variations because of modification of pressure, temperature, and saturation; change of the mechanism of production; and progressive activation of faults, and fractures that affect mechanisms such as stress arching and a nonlinear stress path. Unlike standard compaction-drive simulation, there is no simple linear method to account for the effects of stress on permeability, especially for fractured systems, in which the changes of permeability might be directional, localized, and strongly nonlinear. There are several ways to achieve the coupling between flow and stress (Charlier et al. 2002; Samier et al. 2006; Yale 2002; Chen and Teufel 2000; Koutsabeloulis and Hope 1998; Lewis and Ghafouri 1997; Settari and Walters 1999; Mainguy and Longuemare 2002; Dean et al. 2006; Gutierrez and Lewis 1998; Thomas et al. 2002). The most rigorous coupling is achieved with fully coupled simulators, which not only solve the flow and the mechanical equations simultaneously but also allow for anisotropy and nonlinearity of the rock constitutive model. The feasibility and accuracy of such simulators, as far as complex and large-scale reservoir systems are concerned, have yet to be proved. Partial coupling on the other hand consists of linking a flow simulator with a stress simulator, allowing a good compromise between feasibility and accuracy. A one-way link from flow to stress simulator is often used for subsidence forecasts. However, to solve the compaction-drive problem, one-way coupling is not sufficient. To ensure the compatibility of pore-volume calculations from the flow and the stress simulators, iterations must be performed within each stress-analysis step before proceeding to the next stress step with or without permeability changes.
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Zhang, Guang Ming, Jian Dong Liu, Chun Ming Xiong, Lu He Shen, and Juan Jin. "Shale Reservoirs Multi-Fracture Fracturing Technique and Studies on Reservoirs Stresses." Advanced Materials Research 986-987 (July 2014): 779–85. http://dx.doi.org/10.4028/www.scientific.net/amr.986-987.779.
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Theoretical studies have shown that the generation of the hydraulic fractures reduces or even reverses the stress anisotropy near the fractures and results in increasing the complexity of fractures. A finite element model was established in which the pore pressure elements were used to simulate the behavior of porous media and the pore pressure cohesive elements were adopted to catch the characters of hydraulic fractures. A special fracturing manner was adopted to create complicated fracture networks by reducing or even reversing the stress anisotropy between fractures. The geometries of hydraulic fractures, strains, stresses, pore pressure distributions and fluid pressures within the fractures are obtained. The results of the model are fit well with the corresponding theoretical data. The simulation results show that the stress anisotropy is reduced by the generation of the hydraulic fractures, multiple parallel transverse fractures of horizontal well even reverse the stress anisotropy in some place of the reservoir. The simulation results validate the feasibility of the theoretical studies and the expected complex network fractures could be created by adopting special fracturing manner.
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Pu, Hui, Yuhe Wang, and Yinghui Li. "How CO2-Storage Mechanisms Are Different in Organic Shale: Characterization and Simulation Studies." SPE Journal 23, no. 03 (October 4, 2017): 661–71. http://dx.doi.org/10.2118/180080-pa.
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Summary Widely distributed organic-rich shales are being considered as one of the important carbon-storage targets, owing to three differentiators compared with conventional reservoirs and saline aquifers: (1) trapping of a significant amount of carbon dioxide (CO2) permanently; (2) kerogen-rich shale's higher affinity of CO2; and (3) existing well and pipeline infrastructure, especially that in the vicinity of existing power or chemical plants. The incapability to model capillarity with the consideration of imperative pore-size-distribution (PSD) characteristics by use of commercial software may lead to inaccurate modeling of CO2 injection in organic shale. We develop a novel approach to examine how PSD would alter phase and flow behavior under nanopore confinements. We incorporate adsorption behavior with a local density-optimization algorithm designed for multicomponent interactions to adsorption sites for a full spectrum of reservoir pressures of interests. This feature elevates the limitation of the Langmuir isotherm model, allowing us to understand the storage and sieving capabilities for a CO2/N2 flue-gas system with remaining reservoir fluids. Taking PSD data of Bakken shale, we perform a core-scale simulation study of CO2/N2 flue-gas injection and reveal the differences between CO2 injection/storage in organic shales and conventional rocks on the basis of numerical modeling.
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Asalkhuzina, Guzyal F., Alfred Ya Davletbaev, Ildus L. Khabibullin, and Rina R. Akhmetova. "On the selection of suitable operate durations for injection tests in low permeability reservoirs." Tyumen State University Herald. Physical and Mathematical Modeling. Oil, Gas, Energy 6, no. 1 (2020): 135–49. http://dx.doi.org/10.21684/2411-7978-2020-6-1-135-149.
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The article discusses the aspects of conducting and analyzing the results of hydrodynamic studies of wells (well test) at steady-state injection modes conducted in injection wells in order to assess reservoir pressure and injectivity. The main goal of this work is to determine the necessary duration of injection modes at which reservoir pressure will be determined at the maximum research radius. In view of the considerable duration of the study, in low-permeability reservoirs, the work of the environment wells is taken into account, which, in the process of well research, should have a minimal impact on the results of data interpretation. To this end, we simulated the dynamics of pressure changes for this type of well test for various parameters of the reservoir and the duration of injection modes, taking into account the influence of the work of the surrounding production wells. To solve this problem, we used a numerical model of fluid filtration in an element of a nine-point development system in a low-permeable reservoir. The production and injection of fluid is carried out in wells with main technogenic fractures of hydraulic fracturing. During the simulation, the filtration parameters of the “fracture-formation” system and the duration of the well operating modes were varied, and synthetic data on the change in pressure in the wells were reproduced. Pressure and flow rates at the well operating modes were analyzed by plotting the indicator diagram (ID). Estimates of the extrapolated pressure from the ID graphs were compared with the pressures in the numerical model, in particular, the pressure on the supply circuit and on the study radius. It is shown that for low-permeability formations when studying injection wells using the steady-state injection method, it is necessary to take into account the research radius, which depends on the permeability of the formation and the duration of the injection regimes. Also, the research radius must be taken into account when constructing isobar maps along with the reservoir pressure value.
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Ghedan, Shawket G., Bertrand M. Thiebot, and Douglas A. Boyd. "Modeling Original Water Saturation in the Transition Zone of a Carbonate Oil Reservoir." SPE Reservoir Evaluation & Engineering 9, no. 06 (December 1, 2006): 681–87. http://dx.doi.org/10.2118/88756-pa.
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Summary Accurately modeling water-saturation variation in transition zones is important to reservoir simulation for predicting recoverable oil and guiding field-development plans. The large transition zone of a heterogeneous Middle East reservoir was challenging to model. Core-calibrated, log-derived water saturations were used to generate saturation-height-function groups for nine reservoir-rock types. To match the large span of log water saturation (Sw) in the transition zone from the free-water level (FWL) to minimum Sw high in the oil column, three saturation-height functions per rock type (RT) were developed, one each for the low-, medium-, and high-porosity range. Though developed on a different scale from the simulation-model cells, the saturation profiles generated are a good statistical match to the wireline-log-interpreted Sw, and bulk volume of water (BVW) and fluid volumetrics agree with the geological model. RT-guided saturation-height functions proved a good method for modeling water saturation in the simulation model. The technique emphasizes the importance of oil/brine capillary pressures measured under reservoir conditions and of collecting an adequate number of Archie saturation and cementation exponents to reduce uncertainties in well-log interpretation. Introduction The heterogeneous carbonate reservoir in this study is composed of both limestone and dolomite layers frequently separated by non-reservoir anhydrite layers (Ghedan et al. 2002). Because of its heterogeneity, this reservoir, like other carbonate reservoirs, contains long saturation-transition zones of significant sizes. Transition zones are conventionally defined as that part of the reservoir between the FWL and the level at which water saturation reaches a minimum near-constant (irreducible water saturation, Swirr) high in the reservoir (Masalmeh 2000). For the purpose of this paper, however, we define transition zones as those parts of the reservoir between the FWL and the dry-oil limit (DOL), where both water and oil are mobile irrespective of the saturation level. Both water and oil are mobile in the transition zone, while only oil is mobile above the transition zone. By either definition, the oil/water transition zone contains a sizable part of this field's oil in place. Predicting the amount of recoverable oil in a transition zone through simulation depends on (among other things) the distribution of initial oil saturation as a function of depth as well as the mobility of the oil in these zones (Masalmeh 2000). Therefore, the characterization of transition zones in terms of original water and oil distribution has a potentially large effect on reservoir recoverable reserves and, in turn, reservoir economics.
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Meisingset, K. K. "Uncertainties in Reservoir Fluid Description for Reservoir Modeling." SPE Reservoir Evaluation & Engineering 2, no. 05 (October 1, 1999): 431–35. http://dx.doi.org/10.2118/57886-pa.
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Summary The objective of the present paper is to communicate the basic knowledge needed for estimating the uncertainty in reservoir fluid parameters for prospects, discoveries, and producing oil and gas/condensate fields. Uncertainties associated with laboratory analysis, fluid sampling, process description, and variations over the reservoirs are discussed, based on experience from the North Sea. Introduction Reliable prediction of the oil and gas production is essential for the optimization of development plans for offshore oil and gas reservoirs. Because large investments have to be made early in the life of the fields, the uncertainty in the in-place volumes and production profiles may have a direct impact on important economical decisions. The uncertainties in the description of reservoir fluid composition and properties contribute to the total uncertainty in the reservoir description, and are of special importance for the optimization of the processing capacities of oil and gas, as well as for planning the transport and marketing of the products from the field. Rules of thumb for estimating the uncertainties in the reservoir fluid description, based on field experience, may therefore be of significant value for the petroleum industry. The discussion in the present paper is based on experience from the fields and discoveries where Statoil is an operator or partner, including almost all fields on the Norwegian Continental Shelf,1,2 and all types of reservoir oils and gas condensates except heavy oils with stock-tank oil densities above 940 kg/m3 (below 20° API). Fluid Parameters in the Reservoir Model The following parameters are used to describe the reservoir fluid in a "black oil" reservoir simulation model:densities at standard conditions of stabilized oil, condensate, gas, and water;viscosity (?O) oil formation volume factor (B O) and gas-oil ratio (RS) of reservoir oil;viscosity (?G) gas formation volume factor (B G) and condensate/gas ratio (RSG) of reservoir gas;viscosity (?W) formation volume factor (BW) and compressibility of formation water; andsaturation pressures: bubblepoint for reservoir oil, dew point for reservoir gas. The actual input is usually slightly more complex, with saturation pressure given as a function of depth, with RS and R SG defined as a function of saturation pressure, and with oil and gas viscosities and formation volume factors given as a function of reservoir pressure for a range of saturation pressure values. However, minor changes in saturation pressure versus depth are usually neglected, and the oil dissolved in the reservoir gas can also be neglected (RSG=0) when the solubility is small. Uncertainties in the modeling of other fluid parameters (interfacial tension may for instance be of importance, because of its effect on the capillary pressure), or compositional effects like revaporization of oil into injection gas, are not discussed here. Uncertainties in viscosity, formation volume factor and compressibility of formation water, and density of gas at standard conditions, are judged to be of minor importance for the total uncertainties in the reservoir model. The uncertainty in the salinity of the formation water is discussed here instead, because it is used for calculations of water resistivity for log interpretation, and therefore, affects the estimates of initial water saturation in the reservoir. In a compositional reservoir simulation model, the composition of reservoir oil and gas (with, typically, 4 to 10 pseudocomponents) is given as a function of depth, while phase equilibria and fluid properties are calculated by use of an equation of state. However, the uncertainties in the fluid description can be described in approximately the same way as for a "black oil" model. Quantified uncertainty ranges in the present paper are coarse estimates, aiming at covering 80% of the probability range for each parameter (estimated value plus/minus an uncertainty estimate defining the range between the 10% and 90% probability values3). Prospect Evaluation Assessments of the uncertainties in the reservoir description, as a basis for economic evaluation, are made in all phases of exploration and production. Of course, the complexity in the fluid description increases strongly from prospect evaluation through the exploration phase and further into the production phase, but the main fluid parameters in the reservoir model are the same. The prediction of fluid parameters in the prospect evaluation phase, before the first well has been drilled, is based on reservoir fluid data from discoveries near by, information about source rocks and migration, and empirical correlations. The uncertainties vary strongly from prospect to prospect. The probability as a function of volume for the presence of reservoir oil and gas is usually the most important fluid parameter. The probability for predicting the correct hydrocarbon phase varies from 50% (equal probability for reservoir oil and gas) to 90% (in regions where either oil or gas reservoirs are strongly dominating, or when the reservoir fluid can be expected to be the same as in another discovery near by). For formation volume factors, gas/liquid ratios, viscosities, and densities, an estimate for the most probable value as well as for a high and low possible value is commonly given. The range between the high and low value is often designed to include 80% of the probability range for the parameter, but accurate uncertainty estimates can seldom be made. The ratio of the high and low value is, typically, 1.5 to 50 for R SG 1.1 to 1.5 for B G 1.1 to 2.5 for ?G 1.2 to 3 for RS 1.1 to 2 for BO 1.5 to 5 for (?O and 1.03 to 1.1 for densities of stabilized oil and condensate. From Discovery to Production After a discovery has been made, the fluid description is based on laboratory analyses of reservoir fluid samples from drill-stem tests, production tests, and wireline sampling (RFT, FMT, MDT) in exploration and production wells. Pressure gradients in the reservoirs from measurements during wireline and drill-stem tests, analysis of residual hydrocarbons in core material from various depths, measurements of gas/oil ratio during drill-stem and production tests, and measurements of product streams from the field, give important supplementary information.
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Iranshahr, Alireza, Denis V. Voskov, and Hamdi A. Tchelepi. "A Negative-Flash Tie-Simplex Approach for Multiphase Reservoir Simulation." SPE Journal 18, no. 06 (June 17, 2013): 1140–49. http://dx.doi.org/10.2118/141896-pa.
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Summary Enhanced Oil Recovery (EOR) processes usually involve complex phase behavior between the injected fluid (e.g., steam, hydrocarbon, CO2, sour gas) and the in-situ rock-fluid system. Several fundamental questions remain regarding Equation-of-State (EOS) computations for mixtures that can form three, or more, phases at equilibrium. In addition, numerical and computational issues related to the proper coupling of the thermodynamic phase behavior with multi-component transport must be resolved to accurately and efficiently model the behavior of large-scale EOR processes. Previous work has shown that the adaptive tabulation of tie-simplexes in the course of a compositional simulation is a reliable alternative to the conventional EOS-based compositional simulation. In this paper, we present the numerical results of reservoir flow simulation with adaptive tie-simplex parameterization of the compositional space. We study the behavior of thermal-compositional reservoir displacement processes across a wide range of fluid mixtures, pressures, and temperatures. We show that our approach rigorously accounts for tie-simplex degeneration across phase boundaries. We also focus on the complex behavior of the tie-triangles and tie-lines associated with three-phase, steam injection problems in heterogeneous formations. Our studies indicate that the tie-simplex based simulation is a potential approach for fast EOS modeling of complex EOR processes.
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Scholefield, T., C. P. North, and H. L. Parvar. "RESERVOIR CHARACTERISATION OF A LOW RESISTIVITY GAS FIELD-OTWAY BASIN, SOUTH AUSTRALIA." APPEA Journal 36, no. 1 (1996): 62. http://dx.doi.org/10.1071/aj95004.
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The Katnook, Haselgrove and Ladbroke Grove Fields of southeastern SA are characterised by a lack of resistivity contrast above and below known gas-water contacts, poor hole conditions, complex mineralogy and fresh formation water. A multi-disciplinary review of all available data to characterise the Pretty Hill Sandstone reservoir by integrating core, log and engineering data has enabled a comprehensive picture of reservoir heterogeneity and its influence on log response and well performance to be determined. The availability of extensive core throughout the 6 wells has resulted in the accurate modelling of reservoir porosity and the derivation of a facies-dependent, quantitative permeability log which closely matches drill stem test and production test derived permeability thickness (kh). Previous water saturation assumptions have been shown to be optimistic with Leverett J Function water saturation averaging 50-60 per cent through the reservoir. Detailed facies modelling from the cores extrapolated into areas with no core control has led to the derivation of a geological model which, when integrated into a 3D simulation, has resulted in calculated pressures within 1 per cent of those measured and has enabled the prediction of the pressure response from highly compartmentalised portions of the reservoir. Simulation-derived, material balance and volumetric original-gas-iti-place for the Katnook Field now agree to within 5 per cent.The study has resulted in changes to previously accepted evaluation procedures for wells targeting the Pretty Hill Sandstone.
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McVay, D. A., and J. P. Spivey. "Optimizing Gas-Storage Reservoir Performance." SPE Reservoir Evaluation & Engineering 4, no. 03 (June 1, 2001): 173–78. http://dx.doi.org/10.2118/71867-pa.
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Summary As gas storage becomes increasingly important in managing the nation's gas supplies, there is a need to develop more gas-storage reservoirs and to manage them more efficiently. Using computer reservoir simulation to rigorously predict gas-storage reservoir performance, we present specific procedures for efficient optimization of gas-storage reservoir performance for two different problems. The first is maximizing working gas volume and peak rates for a particular configuration of reservoir, well, and surface facilities. We present a new, simple procedure to determine the maximum performance with a minimal number of simulation runs. The second problem is minimizing the cost to satisfy a specific production and injection schedule, which is derived from the working gas volume and peak rate requirements. We demonstrate a systematic procedure to determine the optimum combination of cushion gas volume, compression horsepower, and number and locations of wells. The use of these procedures is illustrated through application to gas-reservoir data. Introduction With the unbundling of the natural gas industry as a result of Federal Energy Regulatory Commission (FERC) Order 636, the role of gas storage in managing the nation's gas supplies has increased in importance. In screening reservoirs to determine potential gas-storage reservoir candidates, it is often desirable to determine the maximum storage capacity for specific reservoirs. In designing the conversion of producing fields to storage or the upgrading of existing storage fields, it is beneficial to determine the optimum combination of wells, cushion gas and compression facilities that minimizes investment. A survey of the petroleum literature found little discussion of simulation-based methodologies for achieving these two desired outcomes. Duane1 presented a graphical technique for optimizing gas-storage field design. This method allowed the engineer to minimize the total field-development cost for a desired peak-day rate and cyclic capacity (working gas capacity). To use the method, the engineer would prepare a series of field-design optimization graphs for different compressor intake pressures. Each graph consists of a series of curves corresponding to different peak-day rates. Each curve, in turn, shows the number of wells required to deliver the given peak-day rate as a function of the gas inventory level. Thus, the tradeoff between compression horsepower costs, well costs, and cushion gas costs could be examined to determine the optimum design in terms of minimizing the total field-development cost. Duane's method implicitly assumes that boundary-dominated flow will prevail throughout the reservoir. Henderson et al. 2 presented a case history of storage-field-design optimization with a single-phase, 2D numerical model of the reservoir. They varied well placement and well schedules in their study to reduce the number of wells necessary to meet the desired demand schedule. They used a trial-and-error method and stated that the results were preliminary. They found that wells in the poorest portion of the field should be used to meet demand at the beginning of the withdrawal period. Additional wells were added over time to meet the demand schedule. The wells in the best part of the field were held in reserve to meet the peak-day requirements, which occurred at the end of the withdrawal season. Coats3 presented a method for locating new wells in a heterogeneous field. His objective was to determine the optimum drilling program to maintain a contractual deliverability during field development. He provided a discussion of whether wells should be spaced closer together in areas of high kh or in areas of low kh. He found that when f h is essentially uniformly distributed, the wells should be closer together in low kh areas. On the other hand, if the variation in kh is largely caused by variations in h, or if porosity is highly correlated with permeability, wells should be closer together in areas of high kh. Coats' method assumes boundary-dominated flow throughout the reservoir. Wattenbarger4 used linear programming to solve the problem of determining the withdrawal schedule on a well-by-well basis that would maximize the total seasonal production, subject to constraints such as fixed demand schedule and minimum wellbore pressure. Van Horn and Wienecke5 solved the gas-storage-design optimization problem with a Fibonnaci Search algorithm. They expressed the investment requirement for a storage field in terms of four variables: cushion gas, number of wells, purification equipment, and compressor horsepower. They chose as the optimum design the combination of these four variables that minimized investment cost. The authors used an empirical backpressure equation, combined with a simplified gas material-balance equation, as the reservoir model. In this paper we present systematic, simulation-based methodologies for optimizing gas-storage reservoir performance for two different problems. The first is maximizing working gas volume and peak rates for a particular configuration of reservoir, well, and surface facilities. The second problem is minimizing the cost to satisfy a specific production and injection schedule, which is derived from the working gas volume and peak rate requirements. Constructing the Reservoir Model To optimize gas-storage reservoir performance, a model of the reservoir is required. We prefer to use the simplest model that is able to predict storage-reservoir performance as a function of the number and locations of wells, compression horsepower, and cushion gas volume. Although models combining material balance with analytical or empirical deliverability equations may be used in certain situations, a reservoir-simulation model is usually best, owing to its flexibility and its ability to handle well interference and complex reservoirs accurately. It is important to calibrate the model against historical production and pressure data; we must show that the model reproduces past reservoir performance accurately before we can use it to predict future performance with reliability. However, even calibrating the model by history matching past performance may not be adequate. It is our experience that information obtained during primary depletion of a reservoir is often not adequate to predict its performance under storage operations. Primary production over many years may mask layered or dual-porosity behavior that significantly affects the ability of the reservoir to deliver large volumes of gas within a 4- or 5-month period. Wells and Evans6 presented a case history of the Loop gas storage field, which exhibited this behavior. It may be necessary to implement a program of coring, logging, pressure-transient testing, and/or simulated storage production/injection testing to characterize the reservoir accurately.
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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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Wun Moh, Hsiao, Erni Dharma Putra, and Rahel Yusuf. "Application of dynamic simulation to assess the effectiveness of well clean-up in a horizontal gas well." APPEA Journal 57, no. 2 (2017): 617. http://dx.doi.org/10.1071/aj16246.
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Well clean-up operation involves the removal of drilling and completion fluids from the wellbore before diverting the well to production facilities. Natural flow clean-up is preferred due to its relatively low cost and simplicity. Depending on the weight of the initial contents in the wellbore and the reservoir properties, artificial lift assisted clean-up such as nitrogen injection through coiled tubing may be required for some wells to ensure the well clean-up objectives are achieved. Well clean-up is transient in nature thus necessitating the need for a dynamic simulation approach to assess the effectiveness of different clean-up options and arrive at the optimal procedure before embarking on the actual field operation. In the current study, a comprehensive-multiphase-transient-simulator (OLGA) was used to predict the clean-up of a gas well with relatively short horizontal open-hole section and low reservoir pressure. Dynamic simulations of clean-up operations for different scenarios such as mud cake lift-off pressures and uncertainties in well productivity were conducted to assess the effectiveness of natural clean-up. Well clean-up failure could lead to impaired deliverability and potential for preferential flow hotspots. The study also assessed if coiled tubing-assisted operations would be beneficial in cases of natural clean-up being ineffective. This paper demonstrates the importance of using transient simulations to provide useful insights into flow and pressure dynamics inside the wellbore during clean-up which can help engineers to predict, design and optimise well clean-up operations, thus increasing the probability of a successful clean-up operation.
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Stork, R. B. "COMPUTER MODEL SIMPLIFIES GAS FIELD PRODUCTION FORECASTING AND DEVELOPMENT PLANNING." APPEA Journal 27, no. 1 (1987): 335. http://dx.doi.org/10.1071/aj86028.
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Production forecasting of gas fields with complex gathering systems and facilities can be a daunting task. Each individual well and reservoir has its own characteristics which, when combined with connecting pipework and production equipment, creates a highly interrelated network. To obtain meaningful results from reservoir studies, gathering system or production facilities design, the simulation of each segment must be integrated in such a manner that gas flows and pressures are balanced at each node. With the use of a computer model, the task of matching gas well deliverability and production facilities is made easier for gas fields in the Surat/Bowen Basin and Denison Trough.The computer model takes a rigorous approach to gas field deliverability by simultaneously considering a nodal analysis of all reservoirs, wells, piping, compressors, and gas plants. By subjecting the total system description to a calculation procedure that integrates the various components, the influence of a modification to any one component is properly taken into account throughout the entire system. Consequently, variations in line sizing and loops, compressors, infield drilling, and combinations of these can be fully evaluated and optimised.Accurate simulation results are achieved for Surat Basin gas fields by performing comprehensive field pressure surveys of the gathering system and by history matching previous years' production. The model accepts a description of the development strategy for the field so it can selectively commission compressors and tie-in new wells in order to meet projected sales contracts. The result is a complete simulation of the gas field including a calculated schedule for future development which is essential to evaluate the economic feasibility of different field development scenarios.
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Stephen, Karl D., Juan Soldo, Colin Macbeth, and Mike A. Christie. "Multiple Model Seismic and Production History Matching: A Case Study." SPE Journal 11, no. 04 (December 1, 2006): 418–30. http://dx.doi.org/10.2118/94173-pa.
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Summary Time-lapse (or 4D) seismic is increasingly being used as a qualitative description of reservoir behavior for management and decision-making purposes. When combined quantitatively with geological and flow modeling as part of history matching, improved predictions of reservoir production can be obtained. Here, we apply a method of multiple-model history matching based on simultaneous comparison of spatial data offered by seismic as well as individual well-production data. Using a petroelastic transform and suitable rescaling, forward-modeled simulations are converted into predictions of seismic impedance attributes and compared to observed data by calculation of a misfit. A similar approach is applied to dynamic well data. This approach improves on gradient-based methods by avoiding entrapment in local minima. We demonstrate the method by applying it to the UKCS Schiehallion reservoir, updating the operator's model. We consider a number of parameters to be uncertain. The reservoir's net to gross is initially updated to better match the observed baseline acoustic impedance derived from the RMS amplitudes of the migrated stack. We then history match simultaneously for permeability, fault transmissibility multipliers, and the petroelastic transform parameters. Our results show a good match to the observed seismic and well data with significant improvement to the base case. Introduction Reservoir management requires tools such as simulation models to predict asset behavior. History matching is often employed to alter these models so that they compare favorably to observed well rates and pressures. This well information is obtained at discrete locations and thus lacks the areal coverage necessary to accurately constrain dynamic reservoir parameters such as permeability and the location and effect of faults. Time-lapse seismic captures the effect of pressure and saturation on seismic impedance attributes, giving 2D maps or 3D volumes of the missing information. The process of seismic history matching attempts to overlap the benefits of both types of information to improve estimates of the reservoir model parameters. We first present an automated multiple-model history-matching method that includes time-lapse seismic along with production data, based on an integrated workflow (Fig. 1). It improves on the classical approach, wherein the engineer manually adjusts parameters in the simulation model. Our method also improves on gradient-based methods, such as Steepest Descent, Gauss-Newton, and Levenberg-Marquardt algorithms (e.g., Lépine et al. 1999;Dong and Oliver 2003; Gosselin et al. 2003; Mezghani et al. 2004), which are good at finding local likelihood maxima but can fail to find the global maximum. Our method is also faster than stochastic methods such as genetic algorithms and simulated annealing, which often require more simulations and may have slower convergence rates. Finally, multiple models are generated, enabling posterior uncertainty analysis in a Bayesian framework (as in Stephen and MacBeth 2006a).
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Ogunyomi, B. A., T. W. Patzek, L. W. Lake, and C. S. Kabir. "History Matching and Rate Forecasting in Unconventional Oil Reservoirs With an Approximate Analytical Solution to the Double-Porosity Model." SPE Reservoir Evaluation & Engineering 19, no. 01 (November 25, 2015): 070–82. http://dx.doi.org/10.2118/171031-pa.
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Summary Production data from most fractured horizontal wells in gas and liquid-rich unconventional reservoirs plot as straight lines with a one-half slope on a log-log plot of rate vs. time. This production signature (half-slope) is identical to that expected from a 1D linear flow from reservoir matrix to the fracture face, when production occurs at constant bottomhole pressure. In addition, microseismic data obtained around these fractured wells suggest that an area of enhanced permeability is developed around the horizontal well, and outside this region is an undisturbed part of the reservoir with low permeability. On the basis of these observations, geoscientists have, in general, adopted the conceptual double-porosity model in modeling production from fractured horizontal wells in unconventional reservoirs. The analytical solution to this mathematical model exists in Laplace space, but it cannot be inverted back to real-time space without use of a numerical inversion algorithm. We present a new approximate analytical solution to the double-porosity model in real-time space and its use in modeling and forecasting production from unconventional oil reservoirs. The first step in developing the approximate solution was to convert the systems of partial-differential equations (PDEs) for the double-porosity model into a system of ordinary-differential equations (ODEs). After which, we developed a function that gives the relationship between the average pressures in the high- and the low-permeability regions. With this relationship, the system of ODEs was solved and used to obtain a rate/time function that one can use to predict oil production from unconventional reservoirs. The approximate solution was validated with numerical reservoir simulation. We then performed a sensitivity analysis on the model parameters to understand how the model behaves. After the model was validated and tested, we applied it to field-production data by partially history matching and forecasting the expected ultimate recovery (EUR). The rate/time function fits production data and also yields realistic estimates of ultimate oil recovery. We also investigated the existence of any correlation between the model-derived parameters and available reservoir and well-completion parameters.