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Journal articles on the topic "Reservoir simulation pressures"
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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.
Dissertations / Theses on the topic "Reservoir simulation pressures"
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Hardy, Benjamin Arik. "A New Method for the Rapid Calculation of Finely-Gridded Reservoir Simulation Pressures." Diss., CLICK HERE for online access, 2005. http://contentdm.lib.byu.edu/ETD/image/etd1123.pdf.
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Wu, Tao. "Permeability prediction and drainage capillary pressure simulation in sandstone reservoirs." Texas A&M University, 2004. http://hdl.handle.net/1969.1/1496.
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Knowledge of reservoir porosity, permeability, and capillary pressure is essential to
exploration and production of hydrocarbons. Although porosity can be interpreted fairly
accurately from well logs, permeability and capillary pressure must be measured from
core. Estimating permeability and capillary pressure from well logs would be valuable
where cores are unavailable.
This study is to correlate permeability with porosity to predict permeability and
capillary pressures. Relationships between permeability to porosity can be complicated
by diagenetic processes like compaction, cementation, dissolution, and occurrence of clay
minerals. These diagenetic alterations can reduce total porosity, and more importantly,
reduce effective porosity available for fluid flow. To better predict permeability, effective
porosity needs to be estimated. A general equation is proposed to estimate effective
porosity. Permeability is predicted from effective porosity by empirical and theoretical
equations.
A new capillary pressure model is proposed. It is based on previous study, and
largely empirical. It is tested with over 200 samples covering a wide range of lithology
(clean sandstone, shaly sandstone, and carbonates dominated by intergranular pores).
Parameters in this model include: interfacial tension, contact angle, shape factor,
porosity, permeability, irreducible water saturation, and displacement pressure. These
parameters can be measured from routine core analysis, estimated from well log, and
assumed. An empirical equation is proposed to calculate displacement pressure from
porosity and permeability. The new capillary-pressure model is applied to evaluate
sealing capacity of seals, calculate transition zone thickness and saturation above free
water level in reservoirs. Good results are achieved through integration of well log data,
production data, core, and geological concepts.
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Yasin, Ilfi Binti Edward. "Pressure Transient Analysis Using Generated Well Test Data from Simulation of Selected Wells in Norne Field." Thesis, Norges teknisk-naturvitenskapelige universitet, Institutt for petroleumsteknologi og anvendt geofysikk, 2012. http://urn.kb.se/resolve?urn=urn:nbn:no:ntnu:diva-18392.
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Several types of transient well testing in Norne field are presented in this thesis. One production well from each segment in Norne field was participated in different type of test. The well test data of all cases were generated from reservoir simulation. It allows flexibility in modifying reservoir model condition to understand different behavior of pressure response. The tests were first started by producing the well at a constant rate for 10 days, and then shutting-in the well for at least 24 hours. The importance of reservoir model grid refinement, determination of reservoir communication across the fault, and the complexity of horizontal well test analysis are the three main discussions in this thesis work.Series of buildup tests at well D-1H in C-Segment were performed to recognize the significance level of Local Grid Refinement (LGR) near the wellbore. There are two sensitivities performed in the reservoir model, extension of LGR area and increase of LGR factor. Based on pressure responses, wider area of LGR affected permeability estimation, while increase of LGR factor impacted the storage capacity calculation. In the next discussions, LGR near the wellbore becomes a standard procedure in generating well test data.The next type of transient well testing performed in Norne field is interference test. This test was executed at well E-3H as an observation well in E-Segment; while well E-1H and E-2H acted as interfering wells in D- and E-Segments respectively. According to pressure and production trends, it can be ensured both interfering wells are located in different segments. A reservoir communication across segments was identified through pressure drop analysis at well E-3H; hence presence of a major fault between segments is not fully sealed.Transient well testing in horizontal well gives a special and more complex analysis compare to vertical well analysis. A buildup test was examined at horizontal well E-4AH in G-Segment to determine vertical and horizontal permeability. Two flow regimes existed during the test, early-time radial flow and intermediate-time linear flow. They were discovered from pressure versus time plot and pressure derivative analysis. Interpretation results from both flow regimes show a very low kv/kh ratio in the segment around the well.All data tests were interpreted manually using practical equations after doing comprehensive literature studies. The data were also evaluated quantitatively using F.A.S.T WelltestTM – engineering software of pressure transient analysis from Fekete reservoir engineering software and services. Reservoir properties obtained from pressure transient analysis have similar results with the original data on the reservoir model. To simplify the study, production rate which was used in build-up and interference tests are only from oil production basis. In addition, no injections in Norne field were included during the tests to have the same comparison in all analysis. As the future work, any other types of tests are strongly recommended, both in single-well and multiple-well testing, also in vertical and horizontal wells.
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Tingas, John. "Numerical simulation of air injection processes in high pressure light & medium oil reservoirs." Thesis, University of Bath, 2000. https://ethos.bl.uk/OrderDetails.do?uin=uk.bl.ethos.343763.
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Research, pilot scale and field developments of In-Situ Combustion (ISC) for enhanced oil recovery (EOR) in shallow, low pressure, heavy oil reservoirs intensified between the first and the second oil crisis from 1973 to 1981. A decline of interest in EOR followed the collapse of the oil prices in 1986. Renewed interest on in-situ combustion EOR research in the late 1980’s and beginning of the 1990’s was expanded and focused on high pressure medium and light oil reservoirs. The applicability of air injection in deep high pressure light petroleum reservoirs was established by research work of Greaves et al. in 1987 & 1988, Yannimaras et al. in 1991 and Ramey et a l in 1992. Accelerating rate calorimeter (ARC) tests were used to screen the applicability of various types of light oil reservoirs for in-situ combustion EOR by Yannimaras and Tiffin in 1994. The most successful light oil air injection project in the 1990s in the Medicine Pole Hills Unit, Williston Basin, N. Dakota started in 1987 and was reported by Kumar, Fassihi & Yannimaras, in 1994. Low temperature oxidation of light North Sea petroleum was studied at the University of Bath. A high-pressure combustion tube laboratory system was built at Bath University to evaluate performance of medium and light petroleum in-situ combustion processes. Gravity effects and the impact of horizontal wells in Forced Flow In-Situ Combustion Drainage Assisted by Gravity (FFISCDAG) were studied with three-dimensional combustion experiments. In this study, the university of Bath combustion tube experiments have been simulated and history matched. The tube experiments were up-scaled and field simulation studies were performed. A generic PVT characterization scheme based on 5 hydrocarbon pseudo-components was used, which was validated for light Australian and medium ‘Clair’ oil. A generic chemical reaction characterization scheme was used, which was validated for light Australian and medium ‘Clair’ oil. Advanced PVT and chemical reaction characterizations have been recommended for future work with more powerful hardware platforms. Extensive front track and flame extinction studies were performed to evaluate the performance of currently available non-iso-thermal simulators and to appraise their necessity in air injection processes. Comparative ISC field scale numerical simulation studies of Clair medium oil and light Australian petroleum were based on up-scaled combustion tube experimental results. These studies showed higher than expected hydrocarbon recovery in alternative EOR processes for both pre and post water flood implementation of ISC. Further in this study field scale numerical simulation studies revealed high incremental hydrocarbon recovery was possible by gravity assisted forced flow. The applicability of light oil ISC to gas condensate and sour petroleum reservoirs has been examined in this study with promising results. Light petroleum ISC implemented by a modified water flood including oxidants such as H2O2 and NH4NO3 are expected to widen the applicability of ISC processes in medium and light petroleum reservoirs, especially water flooded North Sea reservoirs.
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Samadov, Hidayat. "Analyzing Reservoir Thermal Behavior By Using Thermal Simulation Model (sector Model In Stars)." Master's thesis, METU, 2011. http://etd.lib.metu.edu.tr/upload/12613336/index.pdf.
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It is observed that the flowing bottom-hole temperature (FBHT) changes as a result of production, injection or shutting the well down. Variations in temperature mainly occur due to geothermal gradient, injected fluid temperature, frictional heating and the Joule-Thomson effect. The latter is the change of temperature because of expansion or compression of a fluid in a flow process involving no heat transfer or work. CMG STARS thermal simulation sector model developed in this study was used to analyze FBHT changes and understand the reasons. Twenty three main and five additional cases that were developed by using this model were simulated and relation of BHT with other parameters was investigated. Indeed the response of temperature to the change of some parameters such as bottom-hole pressure and gas-oil ratio was detected and correlation was tried to set between these elements. Observations showed that generally FBHT increases when GOR decreases and/or flowing bottom-hole pressure (FBHP) increases. This information allows estimating daily gas-oil ratios from continuously measured BHT. Results of simulation were compared with a real case and almost the same responses were seen. The increase in temperature after the start of water and gas injection or due to stopping of neighboring production wells indicated interwell communications. Additional cases were run to determine whether there are BHT changes when initial temperature was kept constant throughout the reservoir. Different iteration numbers and refined grids were used during these runs to analyze iteration errorshowever no significant changes were observed due to iteration number differences and refined grids. These latter cases showed clearly that variations of temperature don&rsquo
t occur only due to geothermal gradient, but also pressure and saturation changes. On the whole, BHT can be used to get data ranging from daily gas-oil ratios to interwell connection if analyzed correctly.
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Al, Ghamdi Bander Nasser Ayala H. Luis Felipe. "Analysis of capillary pressure and relative permeability effects on the productivity of naturally fractured gas-condensate reservoirs using compositional simulation." [University Park, Pa.] : Pennsylvania State University, 2009. http://etda.libraries.psu.edu/theses/approved/WorldWideIndex/ETD-4622/index.html.
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Catonho, Humberto Sampaio. "Estudo do processo de combust?o in-situ em reservat?rios maduros de ?leos m?dios e leves (high pressure air injection)." Universidade Federal do Rio Grande do Norte, 2013. http://repositorio.ufrn.br:8080/jspui/handle/123456789/12989.
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Previous issue date: 2013-07-29Nearly 3 x 1011 m3 of medium and light oils will remain in reservoirs worldwide after conventional recovery methods have been exhausted and much of this volume would be recovered by Enhanced Oil Recovery (EOR) methods. The in-situ combustion (ISC) is an EOR method in which an oxygen-containing gas is injected into a reservoir where it reacts with the crude oil to create a high-temperature combustion front that is propagated through the reservoir. The High Pressure Air Injection (HPAI) method is a particular denomination of the air injection process applied in light oil reservoirs, for which the combustion reactions are dominant between 150 and 300?C and the generation of flue gas is the main factor to the oil displacement. A simulation model of a homogeneous reservoir was built to study, which was initially undergone to primary production, for 3 years, next by a waterflooding process for 21 more years. At this point, with the mature condition established into the reservoir, three variations of this model were selected, according to the recovery factors (RF) reached, for study the in-situ combustion (HPAI) technique. Next to this, a sensitivity analysis on the RF of characteristic operational parameters of the method was carried out: air injection rate per well, oxygen concentration into the injected gas, patterns of air injection and wells perforations configuration. This analysis, for 10 more years of production time, was performed with assistance of the central composite design. The reservoir behavior and the impacts of chemical reactions parameters and of reservoir particularities on the RF were also evaluated. An economic analysis and a study to maximize the RF of the process were also carried out. The simulation runs were performed in the simulator of thermal processes in reservoirs STARS (Steam, Thermal, and Advanced Processes Reservoir Simulator) from CMG (Computer Modelling Group). The results showed the incremental RF were small and the net present value (NPV) is affected by high initial investments to compress the air. It was noticed that the adoption of high oxygen concentration into the injected gas and of the five spot pattern tends to improve the RF, and the wells perforations configuration has more influence with the increase of the oil thickness. Simulated cases relating to the reservoir particularities showed that smaller residual oil saturations to gas lead to greater RF and the presence of heterogeneities results in important variations on the RF and on the production curves
Aproximadamente 3 x 1011 m3 de ?leos m?dios e leves restar?o nos reservat?rios ao redor do mundo ap?s a aplica??o dos m?todos convencionais de recupera??o e grande parte desse volume seria recuper?vel com o uso de m?todos especiais. A combust?o in-situ (CIS) ? um m?todo de recupera??o avan?ada de petr?leo no qual um g?s que cont?m oxig?nio ? injetado no reservat?rio onde reage com o ?leo cru para criar uma frente de combust?o de alta temperatura que se propaga pelo reservat?rio. O m?todo HPAI (High Pressure Air Injection) ? uma denomina??o particular do processo de inje??o de ar aplicado em reservat?rios de ?leos leves, onde as rea??es de combust?o s?o dominantes entre 150 e 300?C e a gera??o de flue gas ? o principal fator de deslocamento do ?leo. Um modelo de simula??o de fluxo de um reservat?rio homog?neo foi constru?do para o estudo, o qual foi inicialmente submetido ? produ??o prim?ria, por 3 anos, e em seguida, ao processo de inje??o de ?gua por mais 21 anos. Nesse ponto, com a condi??o madura estabelecida no reservat?rio, foram selecionadas tr?s varia??es desse modelo, de acordo com o fator de recupera??o (FR) obtido, para o estudo da t?cnica de combust?o in-situ (HPAI). Em seguida realizou-se uma an?lise de sensibilidade sobre o FR de par?metros operacionais pr?prios do m?todo: vaz?o de inje??o de ar por po?o, concentra??o de oxig?nio no g?s injetado, esquema de inje??o de ar e configura??o dos canhoneados dos po?os. Essa an?lise, para um per?odo adicional de at? 10 anos produ??o, foi efetuada com o aux?lio da t?cnica de planejamento composto central. O comportamento do reservat?rio e os impactos de par?metros envolvendo as rea??es qu?micas e de particularidades de reservat?rio sobre o FR tamb?m foram avaliados. Adicionalmente foram elaborados uma an?lise econ?mica e um estudo de maximiza??o do FR do processo. As simula??es foram realizadas com o simulador de processos t?rmicos em reservat?rios STARS (Steam, Thermal and Advanced Process Reservoir Simulation) da CMG (Computer Modelling Group). Os resultados mostraram que os FR incrementais foram baixos e que o valor presente l?quido (VPL) ? impactado negativamente pelos elevados investimentos iniciais para compress?o do ar. Observou-se que a ado??o de maiores concentra??es de oxig?nio no g?s injetado e do esquema de inje??o de ar tipo five spot tende a favorecer o FR, e que a configura??o dos canhoneados dos po?os apresenta influ?ncia crescente com o aumento da espessura porosa com ?leo do reservat?rio. Casos simulados referentes ?s particularidades de reservat?rio indicaram que menores satura??es residuais de ?leo ao g?s levam a FR maiores e que a exist?ncia de heterogeneidades resulta em varia??es consider?veis nos FR e nas curvas de produ??o
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Du, Fengshuang. "Investigation of Nanopore Confinement Effects on Convective and Diffusive Multicomponent Multiphase Fluid Transport in Shale using In-House Simulation Models." Diss., Virginia Tech, 2020. http://hdl.handle.net/10919/100103.
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Extremely small pore size, low porosity, and ultra-low permeability are among the characteristics of shale rocks. In tight shale reservoirs, the nano-confinement effects that include large gas-oil capillary pressure and critical property shifts could alter the phase behaviors, thereby affecting the oil or gas production. In this research, two in-house simulation models, i.e., a compositionally extended black-oil model and a fully composition model are developed to examine the nano-pore confinement effects on convective and diffusive multicomponent multiphase fluid transport. Meanwhile, the effect of nano-confinement and rock intrinsic properties (porosity and tortuosity factor) on predicting effective diffusion coefficient are investigated.
First, a previously developed compositionally extended black-oil simulation approach is modified, and extended, to include the effect of large gas-oil capillary pressure for modeling first contact miscible (FCM), and immiscible gas injection. The simulation methodology is applied to gas flooding in both high and very low permeability reservoirs. For a high permeability conventional reservoir, simulations use a five-spot pattern with different reservoir pressures to mimic both FCM and immiscible displacements. For a tight oil-rich reservoir, primary depletion and huff-n-puff gas injection are simulated including the effect of large gas-oil capillary pressure in flow and in flash calculation on recovery estimations. A dynamic gas-oil relative permeability correlation that accounts for the compositional changes owing to the produced gas injection is introduced and applied to correct for changes in interfacial tension (IFT), and its effect on oil recovery is examined. The results show that the simple modified black-oil approach can model well both immiscible and miscible floods, as long as the minimum miscibility pressure (MMP) is matched. It provides a fast and robust alternative for large-scale reservoir simulation with the purpose of flaring/venting reduction through reinjecting the produced gas into the reservoir for EOR.
Molecular diffusion plays an important role in oil and gas migration in tight shale formations. However, there are insufficient reference data in the literature to specify the diffusion coefficients within porous media. Another objective of this research is to estimate the diffusion coefficients of shale gas, shale condensate, and shale oil at reservoir conditions with CO2 injection for EOR/EGR. The large nano-confinement effects including large gas-oil capillary pressure and critical property shifts could alter the phase behaviors. This study estimates the diffusivities of shale fluids in nanometer-scale shale rock from two perspectives: 1) examining the shift of diffusivity caused by nanopore confinement effects from phase change (phase composition and fluid property) perspective, and 2) calculating the effective diffusion coefficient in porous media by incorporating rock intrinsic properties (porosity and tortuosity factor). The tortuosity is obtained by using tortuosity-porosity relations as well as the measured tortuosity of shale from 3D imaging techniques. The results indicated that nano-confinement effects could affect the diffusion coefficient through altering the phase properties, such as phase compositions and densities. Compared to bulk phase diffusivity, the effective diffusion coefficient in porous shale rock is reduced by 102 to 104 times as porosity decreases from 0.1 to 0.03.
Finally, a fully compositional model is developed, which enables us to process multi-component multi-phase fluid flow in shale nano-porous media. The validation results for primary depletion, water injection, and gas injection show a good match with the results of a commercial software (CMG, GEM). The nano-confinement effects (capillary pressure effect and critical property shifts) are incorporated in the flash calculation and flow equations, and their effects on Bakken oil production and Marcellus shale gas production are examined. The results show that including oil-gas capillary pressure effect could increase the oil production but decrease the gas production. Inclusion of critical property shift could increase the oil production but decrease the gas production very slightly. The effect of molecular diffusion on Bakken oil and Marcellus shale gas production are also examined. The effect of diffusion coefficient calculated by using Sigmund correlation is negligible on the production from both Bakken oil and Marcellus shale gas huff-n-puff. Noticeable increase in oil and gas production happens only after the diffusion coefficient is multiplied by 10 or 100 times.Doctor of Philosophy
Shale reservoir is one type of unconventional reservoir and it has extremely small pore size, low porosity, and ultra-low permeability. In tight shale reservoirs, the pore size is in nanometer scale and the oil-gas capillary pressure reaches hundreds of psi. In addition, the critical properties (such as critical pressure and critical temperature) of hydrocarbon components will be altered in those nano-sized pores. In this research, two in-house reservoir simulation models, i.e., a compositionally extended black-oil model and a fully composition model are developed to examine the nano-pore confinement effects on convective and diffusive multicomponent multiphase fluid transport. The large nano-confinement effects (large gas-oil capillary pressure and critical property shifts) on oil or gas production behaviors will be investigated. Meanwhile, the nano-confinement effects and rock intrinsic properties (porosity and tortuosity factor) on predicting effective diffusion coefficient are also studied.
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Praxedes, Tayllandya Suelly. "Efeito da perda de carga e calor no po?o injetor no processo de drenagem gravitacional assistido com vapor e solvente." Universidade Federal do Rio Grande do Norte, 2013. http://repositorio.ufrn.br:8080/jspui/handle/123456789/12991.
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Previous issue date: 2013-11-06Conselho Nacional de Desenvolvimento Cient?fico e Tecnol?gico
Nowadays, most of the hydrocarbon reserves in the world are in the form of heavy oil, ultra - heavy or bitumen. For the extraction and production of this resource is required to implement new technologies. One of the promising processes for the recovery of this oil is the Expanding Solvent Steam Assisted Gravity Drainage (ES-SAGD) which uses two parallel horizontal wells, where the injection well is situated vertically above the production well. The completion of the process occurs upon injection of a hydrocarbon additive at low concentration in conjunction with steam. The steam adds heat to reduce the viscosity of the oil and solvent aids in reducing the interfacial tension between oil/ solvent. The main force acting in this process is the gravitational and the heat transfer takes place by conduction, convection and latent heat of steam. In this study was used the discretized wellbore model, where the well is discretized in the same way that the reservoir and each section of the well treated as a block of grid, with interblock connection with the reservoir. This study aims to analyze the influence of the pressure drop and heat along the injection well in the ES-SAGD process. The model used for the study is a homogeneous reservoir, semi synthetic with characteristics of the Brazilian Northeast and numerical simulations were performed using the STARS thermal simulator from CMG (Computer Modelling Group). The operational parameters analyzed were: percentage of solvent injected, the flow of steam injection, vertical distance between the wells and steam quality. All of them were significant in oil recovery factor positively influencing this. The results showed that, for all cases analyzed, the model considers the pressure drop has cumulative production of oil below its respective model that disregards such loss. This difference is more pronounced the lower the value of the flow of steam injection
Atualmente, a maior parte das reservas de hidrocarbonetos no mundo se encontram na forma de ?leo pesado, ultra-pesado ou betume. Para a extra??o e produ??o desse recurso ? necess?ria a implanta??o de novas tecnologias. Um dos processos promissores para a recupera??o desse ?leo ? a drenagem gravitacional assistida com vapor e solvente (ESSAGD) que utiliza dois po?os horizontais paralelos, onde o injetor ? disposto acima do produtor. A realiza??o do processo se d? mediante a inje??o de um aditivo de hidrocarboneto em baixa concentra??o em conjunto com vapor. O vapor contribui com calor para redu??o da viscosidade do ?leo e o solvente ajuda na miscibilidade, reduzindo a tens?o interfacial entre ?leo/solvente. A principal for?a atuante neste processo ? a gravitacional e a transfer?ncia de calor ocorre por meio da condu??o, convec??o e pelo calor latente do vapor. Neste estudo foi utilizado o modelo discretizado, onde o po?o ? discretizado da mesma forma que o reservat?rio, sendo cada se??o do po?o tratada como um bloco da grade, com conex?o interblocos com o reservat?rio. O presente trabalho tem como objetivo analisar a influ?ncia da perda de carga e calor ao longo do po?o injetor no processo ES-SAGD. O modelo utilizado para estudo trata-se de um reservat?rio homog?neo, semissint?tico com caracter?sticas do Nordeste Brasileiro e as simula??es num?ricas foram realizadas atrav?s do simulador t?rmico STARS da CMG (Computer Modelling Group). Os par?metros operacionais analisados foram: porcentagem de solvente injetado, vaz?o de inje??o de vapor, dist?ncia vertical entre os po?os e qualidade de vapor. Todos eles foram significativos no Fator de Recupera??o de ?leo. Os resultados demonstraram que, para todos os casos analisados, o modelo que considera a perda de carga apresenta produ??o acumulada de ?leo inferior ao seu respectivo modelo que desconsidera tal perda. Essa diferen?a ? mais acentuada quanto menor o valor da vaz?o de inje??o de vapor
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Ying, Winnie (Wai Lai). "Laboratory Simulation of Reservoir-induced Seismicity." Thesis, 2010. http://hdl.handle.net/1807/24919.
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Pore pressure exists ubiquitously in the Earth’s subsurface and very often exhibits a
cyclic loading on pre-existing faults due to seasonal and tidal changes, as well as the
impoundment and discharge of surface reservoirs. The effect of oscillating pore pressure on induced seismicity is not fully understood. This effect exhibits a dynamic variation in effective stresses in space and time. The redistribution of pore pressure as a result of fluid flow and pressure oscillations can cause spatial and temporal changes in the shear strength of fault zones, which may result in delayed and protracted slips on pre-existing fractures.
This research uses an experimental approach to investigate the effects of oscillating pore pressure on induced seismicity. With the aid of geophysical techniques, the spatial and temporal distribution of seismic events was reconstructed and analysed. Triaxial experiments were conducted on two types of sandstone, one with low permeability (Fontainebleau sandstone) and the other with high permeability (Darley Dale sandstone). Cyclic pore pressures were applied to the naturally-fractured samples to activate and reactivate the existing faults. The results indicate that the mechanical properties of the sample and the
heterogeneity of the fault zone can influence the seismic response. Initial seismicity was induced by applying pore pressures that exceeded the previous maximum attained during the
experiment. The reactivation of faults and foreshock sequences was found in the
Fontainebleau sandstone experiment, a finding which indicates that oscillating pore pressure can induce seismicity for a longer period of time than a single-step increase in pore pressure.
The corresponding strain change due to cyclic pore pressure changes suggests that
progressive shearing occurred during the pore pressure cycles. This shearing progressively damaged the existing fault through the wearing of asperities, which in turn reduced the friction coefficient and, hence, reduced the shear strength of the fault. This ‘slow’ seismic mechanism contributed to the prolonged period of seismicity. This study also applied a
material forecast model for the estimation of time-to-failure or peak seismicity in
reservoir-induced seismicity, which may provide some general guidelines for short-term field case estimations.
Book chapters on the topic "Reservoir simulation pressures"
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González, Pedro, Manuel Kindelan, and Francisco J. Mustieles. "Modelling Capillary Pressure in a Streamline Reservoir Simulator Using Operator Splitting." In Progress in Industrial Mathematics at ECMI 2002, 291–96. Berlin, Heidelberg: Springer Berlin Heidelberg, 2004. http://dx.doi.org/10.1007/978-3-662-09510-2_38.
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"RELATIVE PERMEABILITY AND CAPILLARY PRESSURE DATA." In Lecture Notes on Applied Reservoir Simulation, 85–109. WORLD SCIENTIFIC, 2005. http://dx.doi.org/10.1142/9789812775276_0004.
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Wei, Chongtao, Lei Man, and Jian Meng. "Numerical simulation of geologic history evolution and quantitative prediction of CBM reservoir pressure." In Mining Science and Technology, 325–29. CRC Press, 2004. http://dx.doi.org/10.1201/9780203022528-64.
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Man, Lei, Jian Meng, and Chongtao Wei. "Numerical simulation of geologic history evolution and quantitative prediction of CBM reservoir pressure." In Mining Science and Technology, 325–29. Taylor & Francis, 2004. http://dx.doi.org/10.1201/9780203022528.ch64.
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Walker, James C. G. "How to Calculate a Compositional History." In Numerical Adventures with Geochemical Cycles. Oxford University Press, 1991. http://dx.doi.org/10.1093/oso/9780195045208.003.0004.
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The most interesting theoretical problems in Earth system science cannot be solved by analytical methods; their solutions cannot be expressed as algebraic expressions; and so numerical solutions are needed. In this chapter I shall introduce a method of numerical solution that can be applied to a wide range of simulations and yet is easy to use. In later chapters I shall elaborate and apply this method to a variety of situations. All numerical solutions of differential equations involve some degree of approximation. Derivatives—properly defined in terms of infinitesimally small increments—are approximated by finite differences: dy/dx is approximated by dely/delx, whose accuracy increases as the finite difference, delx, is reduced. A large value of delx may even cause numerical instability, yielding a numerical solution that is altogether different from the true solution of the original system of differential equations. But a small value of delx generally implies that many steps must be taken to evolve the solution from a starting value of x to a finishing value. A numerical solution, therefore, requires a trade-off between computational speed and accuracy. We seek an efficient and stable method of calculation that provides accuracy appropriate to our knowledge of the physical system being simulated. The problem described in this chapter can be easily solved analytically, and the analytical solution serves as a check on the accuracy of the numerical solutions. As a simple example of a global geochemical simulation, consider the exchange of carbon dioxide between the ocean and the atmosphere. The atmosphere contains 5.6 × 1016 moles of carbon dioxide (cf. Walker, 1977), a quantity that I assume to be in equilibrium with the ocean. In this illustration I assume that the oceanic reservoir is very large and therefore does not change with time. According to Broecker and Peng (1982, p. 680) the annual exchange of carbon dioxide between ocean and atmosphere is 6.5 × 1015 moles. The rate of transfer from atmosphere to ocean is proportional to the amount in the atmosphere; the flow from ocean to atmosphere is constant. Figure 2-1 summarizes this system. The amount of carbon dioxide in the atmosphere is proportional to the partial pressure.
Conference papers on the topic "Reservoir simulation pressures"
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Tleuberdinov, Marlen, Nurlan Zhulomanov, and Alimzhan Adilbayev. "A Comparative Study of Various Laboratory Methods for Capillary Pressures Determination in Conventional Oil Fields of Kazakhstan." In SPE Reservoir Characterisation and Simulation Conference and Exhibition. Society of Petroleum Engineers, 2015. http://dx.doi.org/10.2118/175557-ms.
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Haruna, Onuh, David Ogbe, and Chike Nwosu. "Reservoir Characterization for Improved Petrophysical Properties Predictability & Validations: Capillary Pressures and Permeability (Niger Delta Province as Case Study)." In SPE Reservoir Characterization and Simulation Conference and Exhibition. Society of Petroleum Engineers, 2013. http://dx.doi.org/10.2118/165958-ms.
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Hardy, B. A., H. B. Hales, and L. L. Baxter. "A New Method for the Rapid Calculation of Finely Gridded Reservoir Simulation Pressures." In Canadian International Petroleum Conference. Petroleum Society of Canada, 2005. http://dx.doi.org/10.2118/2005-112.
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Aavatsmark, I. "Interpretation of Well-cell Pressures on Hexagonal K-orthogonal Grids in Numerical Reservoir Simulation." In ECMOR XV - 15th European Conference on the Mathematics of Oil Recovery. Netherlands: EAGE Publications BV, 2016. http://dx.doi.org/10.3997/2214-4609.201601750.
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Rodriguez M., Fernancelys. "Characterization and Modeling of Asphaltenes for Complex Reservoirs in Venezuela: State of the Art." In ASME 2020 39th International Conference on Ocean, Offshore and Arctic Engineering. American Society of Mechanical Engineers, 2020. http://dx.doi.org/10.1115/omae2020-18502.
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Abstract Asphaltenes are complex hydrocarbon molecules that are in suspension in the oil, stabilized by resins, which may cause severe production issues at reservoir and surface conditions. High asphaltene and resin contents is one of the main characteristics of the Venezuelan unconventional oils (highly viscous oils) in the Orinoco Oil Belt. This high concentration of resins in the oil maintains the aggregates of asphaltenes dissolved in the continue oil phase avoiding asphaltene precipitation/ flocculation/deposition issues at field conditions as some Venezuelan conventional oil reservoirs located in northern Monagas State in which unfavorable resins/asphaltene (R/A) ratios promote the precipitation of asphaltenes. Conventional oil reservoirs in northern Monagas show gravitational segregation, this is the case of Carito-Mulata and Santa Barbara Field, varying from an upper zone of critical fluid behavior to a black oil zone in the lowest part of the structure in which the current pressure levels induce asphaltene precipitation, causing problems by plugging reservoirs, wells and pipelines, severely affecting oil and gas production. This causes increased production costs (chemical cleaning) and/or irreversible formation damage when reservoir pressures are less than asphaltene precipitation/flocculation onset pressures. Therefore it is necessary to characterize the asphaltene thermodynamic behavior and include this in reservoir numerical-simulation models, with the aim of increasing the reliability of the results and optimizing production strategies. Reproducing the thermodynamic behavior of asphaltenes is very complex, both experimentally and in numerical simulation, especially in terms of description and measurement of the degree of asphaltene-porous media interaction and the effect of injected fluids into the reservoir (EOR methods such as miscible/non-miscible gas injection or chemical flooding). Nevertheless, efforts have been done by the Venezuelan National Oil Company and collaborators, both at laboratory and simulation scales, to study the asphaltene thermodynamic behavior and the effect of permeability reduction in the porous media and its impact on the production profiles for complex Venezuelan reservoirs. This article presents a literature review of the Venezuelan experience for the characterization and modeling of asphaltenes for conventional and heavy oil reservoirs.
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Nakajima, Kenta, and Michael King. "Development and Application of Fast Simulation Based on the PSS Pressure as a Spatial Coordinate." In SPE Annual Technical Conference and Exhibition. SPE, 2021. http://dx.doi.org/10.2118/206085-ms.
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Abstract Recent studies have shown the utility of the Fast Marching Method and the Diffusive Time of Flight for the rapid simulation and analysis of Unconventional reservoirs, where the time scale for pressure transients are long and field developments are dominated by single well performance. We show that similar fast simulation and multi-well modeling approaches can be developed utilizing the PSS pressure as a spatial coordinate, providing an extension to both Conventional and Unconventional reservoir analysis. We reformulate the multi-dimensional multi-phase flow equations using the PSS pressure drop as a spatial coordinate. Properties are obtained by coarsening and upscaling a fine scale 3D reservoir model, and are then used to obtain fast single well simulation models. We also develop new 1D solutions to the Eikonal equation that are aligned with the PSS discretization, which better represent superposition and finite sized boundary effects than the original 3D Eikonal equation. These solutions allow the use of superposition to extend the single well results to multiple wells. The new solutions to the Eikonal equation more accurately represent multi-fracture interference for a horizontal MTFW well, the effects of strong heterogeneity, and finite reservoir extent than those obtained by the Fast Marching Method. The new methodologies are validated against a series of increasingly heterogeneous synthetic examples, with vertical and horizontal wells. We find that the results are systematically more accurate than those based upon the Diffusive Time of Flight, especially as the wells are placed closer to the reservoir boundary or as heterogeneity increases. The approach is applied to the Brugge benchmark study. We consider the history matching stage of the study and utilize the multi-well fast modeling approach to determine the rank quality of the 100+ static realizations provided in the benchmark dataset against historical data. The multi-well calculation uses superposition to obtain a direct calculation of the interaction of the rates and pressures of the wells without the need to explicitly solve flow equations within the reservoir model. The ranked realizations are then compared against full field simulation to demonstrate the significant reduction in simulation cost and the corresponding ability to explore the subsurface uncertainty more extensively. We demonstrate two completely new methods for rapid reservoir analysis, based upon the use of the PSS pressure as a spatial coordinate. The first approach demonstrates the utility of rapid single well flow simulation, with improved accuracy compared to the use of the Diffusive Time of Flight. We are also able to reformulate and solve the Eikonal equation in these coordinates, giving a rapid analytic method of transient flow analysis for both single and multi-well modeling.
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Yang, Yibo, Teresa Regueira, Hilario Martin Rodriguez, Alexander Shapiro, Erling Halfdan Stenby, and Wei Yan. "Determination of Methane Diffusion Coefficients in Live Oils for Tight Reservoirs at High Pressures." In SPE Annual Technical Conference and Exhibition. SPE, 2021. http://dx.doi.org/10.2118/206100-ms.
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Abstract Molecular diffusion plays a critical role in gas injection in tight reservoirs such as liquid-rich shale. Despite recent efforts on measuring diffusion coefficients at high pressures, there is a general lack of the diffusion coefficients in live oil systems at reservoir conditions relevant to the development of these tight reservoirs. The reported diffusion coefficients often differ in orders of magnitude, and there is no consensus on the reliability of the common correlations for liquid phase diffusion coefficients, such as the extended Sigmund correlation. We employed the constant volume diffusion method to measure the high-pressure diffusion coefficients in a newly designed high-pressure tube. The experimental method was first validated using methane + hexadecane and methane + decane, and then used to measure the methane diffusion coefficients in two live oils at reservoir conditions. The obtained data were processed by compositional simulation to determine the diffusion coefficients. The diffusion coefficients measured for methane + hexadecane and methane + decane are in agreement with the existing literature data. For methane + live oil systems, however, the diffusion coefficients estimated by the extended Sigmund correlation are much lower than the measured results. An over ten times adjustment is needed to best fit the pressure decay curves. A further check reveals that for live oil systems, the reduced densities are often in the extrapolated region of the original Sigmund model. The curve in this region of the extended Sigmund correlation has a weak experimental basis, which may be the reason for its large deviation. The estimates from other correlations like Wilke-Chang and Hayduk-Minhas also give very different results. We compared the diffusion coefficients in high-pressure oils reported in the literature, showing a large variation in the reported values. All these indicate the necessity for further study on accurate determination of high-pressure diffusion coefficients in live oils of relevance to shale and other tight reservoirs.
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El Hajj, Hicham, Uchenna Odi, and Anuj Gupta. "Study of Use of Supercritical CO2 to Enhance Gas Recovery and its Interaction With Carbonate Reservoirs." In ASME 2013 32nd International Conference on Ocean, Offshore and Arctic Engineering. American Society of Mechanical Engineers, 2013. http://dx.doi.org/10.1115/omae2013-11253.
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It is well known that with continued production from wet gas reservoirs, the reservoir pressure eventually falls below the dew point pressure leading to condensation and loss of gas productivity in the reservoir. The concept of simultaneously injecting CO2 in a gas reservoir for long term storage while at the same time accelerating production of the natural gas is intriguing and promising. CO2 may also interact with carbonate matrix by changing porosity and permeability of the host rock; this is true for reservoirs that are found in the Gulf Region. To maintain field gas production targets, operators routinely set the bottom hole pressure below the dew point pressure which results in condensate blockage. Injecting CO2 can delay the onset of condensate blockage by reducing the dew point pressure of the condensate blockage zone. The approach illustrated, utilizes CO2 to delay the onset of condensate blockage. Factors such as improved effusion were analyzed to justify the use of CO2 for wellbore condensate removal and enhanced gas recovery (EGR). Experimental verification of a new method of determining dew point pressures for wet gas fluids is presented in this work and compared to simulation results. Core floods experiments with carbon dioxide were conducted in a core sample analogue to carbonate at reservoir conditions in order to study the interaction between CO2 and carbonate reservoir. CO2 sequestration in carbonate formation was evaluated by XRF and AFM. Experimental and simulation results show increases in productivity index after CO2 injection. Increases in productivity index were caused by CO2 evaporating the condensate blockage. Condensate vaporization was caused by CO2 reducing the dew point pressure of the condensate. Carbonate aging in presence of CO2 shows two mechanism of CO2 trapping which are dissolution and mineralization.
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Blanco, Yon, Ben Fletcher, Robert Webber, Alistair Maguire, and Velerian Lopes. "FIELDWIDE DYNAMIC PRESSURE SURVEILLANCE WITH FPWD TECHNOLOGY." In 2021 SPWLA 62nd Annual Logging Symposium Online. Society of Petrophysicists and Well Log Analysts, 2021. http://dx.doi.org/10.30632/spwla-2021-0107.
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Reservoir management utilizes time-lapse pressure data that is captured over years in order to monitor reservoir development. Several methods can be used to establish field-wide hydraulic lateral and/or vertical connectivity: well testing, monitoring of permanent downhole gauges, wireline and LWD formation testers. While a typical formation pressure survey provides information about reservoir depletion or charge (production or injection), in a field with several wells it is not clearly understood where the pressure disturbances are coming from, which can hamper further field development decision making in terms of infill well selection and drilling. A novel method is introduced where a Formation Pressure While Drilling (FPWD) tool is run in UKCS wells and used to acquire interference data while drilling. Initially reservoir pressures are acquired as soon as practically possible after drilling. Having established these benchmark pressures, nearby injectors and/or producers can be started or shut in one at a time. Drilling is then resumed and after a certain time has elapsed since the benchmark pressure acquisition (typically at least 12 hours), the pressure measurements are repeated using the FPWD tool to evaluate the influence of the created transients in order to prove or disprove either lateral or vertical hydraulic connectivity across reservoirs. This way, the influence of a single offset well is evaluated in real time over the reservoir being currently drilled. This helps in the determination of interference pattern whereby injector wells can be judged for selective zone injections and producers can be rated in terms of zonal contribution which can help in completion design. These direct pressure measurements can illuminate reservoir pressure complexity seen in mature fields and provide operators with the means to safely and effectively construct wells to develop brownfields. The pressure changes obtained are used not only by reservoir engineers as an additional source of dynamic data into the reservoir simulation model but also help geologists in refining the geological or basin model. Two applications of real-time interference testing using FPWD from a recent drilling campaign are shown. In the first application, communication between wells is tested to reduce the risk of accidentally completing a well in an area of the field that experiences insufficient injection support. In the second application, real-time interference testing is used to identify a specific zone in a multi-layered reservoir sequence in order to enable selective completion.
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Liu, Xiaolei, Akkharachai Limpasurat, Gioia Falcone, and Catalin Teodoriu. "Investigation of Back Pressure Effects on Transient Gas Flow Through Porous Media via Laboratory Experiments and Numerical Simulation." In ASME 2014 33rd International Conference on Ocean, Offshore and Arctic Engineering. American Society of Mechanical Engineers, 2014. http://dx.doi.org/10.1115/omae2014-24648.
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When developing a transient numerical reservoir simulator, it is important to consider the back pressure effects that waves propagating from one end of the porous medium will have on the temporal distribution of pore fluid pressure within the medium itself. Such waves can be triggered by changing boundary conditions at the interface between reservoir and wellbore. An example is given by the transient reservoir response following pressure fluctuations at the wellbore boundary for gas wells suffering from liquid loading. Laboratory experiments were performed using a modified Hassler cell to mimic the effect of varying downhole pressure on gas flow in the near-wellbore region of a reservoir. Gauges were attached along a sandstone core to monitor the pressure profile. The results of the experiments are shown in this paper. A numerical code for modelling transient flow in the near-wellbore region was run to mimic the experiments. The comparisons of simulations and laboratory test results are presented here, for the initial and final steady-state flowing conditions, and where the inlet pressure was maintained constant while initiating a transient pressure build up at the core outlet. The concept of the U-shaped pressure profile along the near-wellbore region of a reservoir under transient flow conditions, originally proposed by Zhang et al. [1], was experimentally and numerically reproduced for single-phase gas flow. This is due to a combination of inertia and compressibility effects, leading to the reservoir response not being instantaneous. The results suggest that, in two phase gas-liquid conditions, liquid re-injection could occur during liquid loading in gas wells. From the experimental results, the U-shaped curves were more obvious and of longer duration in the case of greater outlet pressure. The transition from the initial to the final steady state condition occurred rapidly in all the cases shown here, with the U-shaped pressure profile appearing only over a relatively short time (at the small scale and low pressures tested in this study).