Black Oil Simulator Research Articles

Field-split preconditioned active-set reduced-space algorithm for complex black oil reservoir simulation at large-scale

Accurate black oil reservoir simulation is important for the understanding of underground resources in hydrology and petroleum reservoir engineering. The success of fast prediction relies on a robust and scalable black oil simulator, which can handle the complex subsurface fluid dynamics with coupling several different physical processes, and meanwhile run efficiently on distributed memory parallel computers. In this work, we introduce a highly parallel simulator to accurately compute the reservoir flow coupling with wells, including some adaptive fully implicit schemes for the temporal discretization, the improved active-set reduced-space algorithm for the nonlinear algebraic system, and several types of field-split methods for preconditioning. This parallel simulator is applied on the domain decomposition framework, which is designed to overcome the computational issues of traditional simulators implemented for personal computers or small workstations. High-resolution reservoir simulation results on the Society of Petroleum Engineers (SPE) comparative solution project or real-field cases are obtained and analyzed, and the parallel performance of the algorithm is studied on a supercomputer with scaling up to 27440 processor cores. The numerical experiments indicate that the proposed black oil simulator is capable of accurately predicting the highly complex physical processes and interactions between wells and the reservoir for full field scale simulation.

Developing an inflow performance relationship for predicting hydrocarbon recovery from horizontal wells operating in partially naturally fractured reservoirs under solution-gas drive

Inflow performance relationships (IPR) have long been recognized as one of the most important diagnostic tools for predicting hydrocarbon production performance. Current IPR models associated with naturally fractured reservoirs (NFR) are only applicable to fully fractured NFR models. No previous research has investigated the IPR of partially naturally fractured reservoirs (PNFR). This work aims to develop an IPR model for horizontal wells producing from PNFRs under solution-gas drive (SGD). A 3D black oil simulator is utilized to generate the required IPR data. A total of 236 IPR plots and 26 future IPR plots are generated throughout six major cases varying in fracture intensity (FI), dimensionless well length (LD ), matrix permeability (km ), and fracture porosity (ϕf ). Percolation theory validated the existence of a critical FI threshold at which complex IPR behaviors manifest. Sensitivity analysis reveals that IPR shape becomes more complex as LD reduces. ϕf has negligible effects on IPR and future IPR behaviors. A logarithmic cycle proportionality governs the relationship between km and absolute open flow potential (qo,AOF ) in future IPR curves. A generalized IPR model applicable to horizontal wells producing from SGD PNFRs is developed through the non-linear regression of IPR candidates. The model is validated against field data and complex IPR behaviors.

Development of a numerical simulator for modeling seismic EOR

Natural earthquakes, culture noise, and artificially induced mechanical waves have been reported to affect the productivity of oil wells. Sources emitting waves in the seismic frequency range, between 1 and 1000 Hz, have been used as an enhanced oil recovery (EOR) tool for improving oil production rates. Theories suggest several mechanisms for the increased oil production rate including (AbuZaid et al., 2021): overcoming the capillary forces holding the oil phase in place (Alzahrani and Abbas, 2020), improving the relative permeability of oil, and (Ariadji, 2005) decreasing viscosity as temperature rises from waves attenuation. In this work, a fully implicit modified black oil simulator has been developed. The fluid flow simulator is coupled with a ray tracing module for simulating waves propagation in the model. Wave simulation is used to calculate the effect of seismic waves on capillary pressure, oil relative permeability, and reservoir temperature. It is also used to investigate the applicability of the proposed mechanisms for explaining the observed enhancement in oil recovery due to seismic waves. This seismic stimulation simulator can provide insights on the response of wells’ production rates at various field characteristics and seismic tool(s) operation conditions, explain field results, and design field implementation of seismic EOR.

Technique Evaluates Polymer Injectivity in High-Salinity/High-Temperature Carbonates

_ This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 211451, “Assessment of World-First Two-Polymer Injectivity Tests Performed in Two Giant High-Salinity/High-Temperature Carbonate Reservoirs Using Single-Well Simulation Models and Pressure-Falloff Analysis,” by Juan M. Leon, Shehadeh K. Masalmeh, SPE, and Ali M. Al-Sumaiti, SPE, ADNOC, et al. The paper has not been peer reviewed. _ The complete paper presents the interpretation of two polymer injectivity tests (PITs) performed in two giant light-oil high-salinity/high-temperature (HS/HT) carbonate reservoirs onshore Abu Dhabi. The detailed data acquired in both tests were used to evaluate both polymer injectivity at representative field conditions and in-depth mobility reduction. The interpretation of the pressure transient analysis (PTA) of the pressure falloffs (PFOs) and the mechanistic 3D simulation models of the two PITs confirmed the generation of polymer banks and demonstrated effective propagation of the polymer into the reservoirs at target concentrations and representative rates of future interwell pilots. Introduction The reservoirs tested in the PITs can be described as heterogeneous carbonate reservoirs divided into upper and lower zones. Upper-zone porosities range between 20 and 30%; permeability ranges from 10 to 1000 md. In contrast, the lower zone has porosities and permeabilities ranging from 10 to 30% and from 1 to 20 md, respectively. The main production mechanisms in the reservoirs are peripheral water injection, middip-pattern water injection, and crestal hydrocarbon gas injection in the gas cap. The reservoirs have been developed through long horizontal wells oriented into the lower zones to allow a more-homogeneous sweep. However, the injected fluids in the lower zone travel quickly through the upper zone not far from the injection wells and around the producers into the lower zone. This water or gas inverse coning results in bypassed oil in the lower zone. To face this challenge, the operator has investigated simultaneous injection of miscible CO2 gas and polymer (SIMGAP) for reservoirs with an approximately 10-fold permeability contrast between the lower and upper zones and simultaneous injection of water and polymer (SIWAP) for reservoirs with a permeability contrast of 100-fold or greater between the lower and upper zones. These techniques rely on reducing mobility by polymer injection in the upper zone to provide a pressure barrier and reduce crossflow of the higher-mobility fluid injected into the lower zone. PIT Simulation Model Setup A single-well radial simulation model was built for PIT 1 to assess near-wellbore phenomena by minimizing in-situ velocity and shear-rate calculation errors compared with Cartesian coordinate grids. For interpretation of PIT 2, a mechanistic Cartesian 3D thermal black-oil simulation model was built by extracting a subsector from the last available static geomodel, preserving well architecture and grid resolution in the extracted subsector. The radial simulation model was found unsuitable for PIT 2 because the injector well presented a very high deviated section in the target reservoir, while the long string presented a long horizontal section. Therefore, the polymer injectivity and polymer bank propagation in the upper reservoir might not be represented properly using a vertical well. Different local-grid-refinement (LGR) levels were implemented around the perforation length (upper zone), while the lower zone was in the root grid. The minimum cell radius in the model was determined to be 1.3 ft to avoid errors in well-index calculations considering the well-flow model. Thus, three LGR levels were applied.

Hydrogen-brine mixture PVT data for reservoir simulation of hydrogen storage in deep saline aquifers

An accurate assessment of hydrogen storage mechanisms in an aquifer storage project requires detailed flow and transport modeling. The equation-of-state (EOS) based compositional phase equilibrium approaches make these models computationally expensive. This paper proposes using the black-oil simulation approach for the specific case of hydrogen storage in saline aquifers to reduce the computational burden of the flow simulations. We present a simple and efficient algorithm for converting hydrogen-brine phase equilibrium compositional data obtained from the Redlich and Kwong EOS into black-oil PVT data. The algorithm accurately predicts the hydrogen-brine transport properties required for the black-oil flow simulations of underground hydrogen storage. Numerical simulations for a simple cyclic hydrogen injection-production case reveal that the black-oil simulations are at least one order of magnitude faster than the compositional ones without loss of accuracy. These results support applying the black-oil PVT model and the simulation approach for numerical simulations of large-scale hydrogen storage in deep saline aquifers.

A Sensitivity Study of Salt Concentration in Brine to The Solubility of CO2 in Saline Aquifers

In CO2 sequestration, four main trapping mechanisms are expected such as structural, residual, solubility, and mineral trapping. This paper aims to analyse the impact of salt concentration in brine on the CO2 solubility trapping mechanism in the saline aquifer. The CO2 solubility decreases with salinity. In this study, a sensitivity run will be done on an existing saline aquifer dataset to investigate the impact of salt concentration using the compositional mode simulation approach. Different types of salt will give different levels of CO2 solubility in an Aqueous solution, for example, at isotherm conditions and at increasing pressure, the same amount of NaCl will be more soluble. At the same temperature condition, higher salinity will decrease CO2 solubility with pressure increases and produce a salting-out phenomenon at the near injector area. The reference dataset was completed using the black-oil simulation with the gas-water system, where the CO2 act as the gas phase and brine as the water phase. The black-oil simulator can only handle isotherm and a single salinity value, which is 200,000 ppm in this case. Thus, this study is expected to give more information and improve the solubility trapping mechanism in a saline aquifer.

Calibration of compositional VLP in black oil simulator for future historical adjustment with well head pressure data

Calibration of compositional VLP in black oil simulator for future historical adjustment with well head pressure data

Impact of karstification in trapping mechanisms of CO2 storage

A carbonate-depleted carbonate gas field located offshore Sarawak has been identified as potential candidate for CO2 sequestration site in conjunction with another high CO2 gas field development for commercialization efforts. The field has undergone a feasibility study to evaluate potential geochemical reactions specifically on trapping mechanisms and storage capacity associated with CO2 injection. A detail 3D reactive transport modelling study was conducted to quantify on the four different trapping mechanism: structural, residual, solubility, and mineral trapping during and post-injection. The model was developed by first converted the available field history matched black oil simulation model into compositional 3D model, in which CO2 is treated as separate component in the reservoir through the production and injection processes. The study covered 22 years of gas production history forecast followed by 27 years of injection and 1000 years of post-CO2 injection in the gas column reservoir. The results show that the field has potential to store and sequestrate CO2 up to for 79% structural trapping, 19% residual trapping, 3% solubility trapping and no mineral trapping after 1000 years of post-injection period.

Dynamic PVT model for CO2-EOR black-oil simulations

A well-planned CO2EOR operation can help meet an ever-increasing need for energy and at the same time reduce the total CO2 footprint from the energy production. Good simulation studies are crucial for investment decisions where increased oil recovery is optimized and balanced with permanent CO2 storage. It is common to use a compositional simulator for CO2 injection to accurately calculate the PVT properties of the mixture of oil and CO2. Compositional simulations have significantly increased simulation time compared to blackoil simulations. Large simulation studies where many simulations are used either to represent uncertainty and/or optimize the results can thus be unpractical. On the other hand existing blackoil formulations often poorly represent the PVT properties of the oil-CO2 mixtures. We therefore present an extended blackoil formulation with dynamic blackoil properties that depends on the fraction of CO2 in the cell. These properties represents the density and viscosity of the hydrocarbon - CO2 mixture more accurately and thus give results closer to the compositional simulator. The dynamic blackoil functions are calculated from numerical slim-tube experiments based on one-dimensional equation-of-state (EOS) simulations. The same simulations also gives estimates of the minimum-miscibility pressure (MMP). We present examples based on data from the Fifth Comparative Solution Project: Evaluation of Miscible Flood Simulators, but uses CO2 as the injection gas. These examples shows that the new blackoil model gives results that are closer to compositional simulations compared to existing blackoil formulations. The model is implemented in the Flow simulator. The Flow simulator is developed as part of the open porous media (OPM) project and is an openly developed and free reservoir simulator that is capable of simulating industry relevant reservoir models with similar single and parallel performance as commercial simulators.

Simulation Studies on Comparative Evaluation of Waterflooding and Gas Injection in Niger Delta Thin-Bed Reservoir

There is a need to increase ultimate recovery from petroleum reservoirs. In order to guarantee efficient resource extraction from reservoirs, primary recovery methods cannot be relied on throughout the life of a well. There is a time in the life of a reservoir when the primary energy will not be sufficient to ensure economic recovery. Complete abandonment of the reservoir at this point may not be a sound engineering decision given the huge investments in developing the asset. Secondary recovery methods present potentials for the recovery of the other trapped resources. The choice of the secondary recovery means depends on the reservoir and geologic conditions and should be determined by modeling and simulation. In this work, a simulation study is conducted for Niger Delta Field ABX2 to determine the performance of water-flooding and gas injection in the recovery of the asset after the primary recovery stage. ECLIPSE Blackoil simulator was used for the modeling and simulation. An equal reservoir rectangular grid block was designed for both the waterflooding and water injection comprising a total of 750 grid cells. Water and gas were injected in both cases at an injection rate of 11,000 stb/d and 300,000 scf/d for waterflooding and gas injection respectively. From the results of the simulation, it was realized that waterflooding gave a higher total oil recovery than gas injection. The difference in oil recovery from water-flooding and gas injection amounted to 0.08 MMstb/d. The Field Oil Recovery Efficiency (FOE) for waterflooding and gas injection was 38% and 16% respectively giving a difference of 22%. The waterflooding method was troubled with excessive water cuts due to water breakthroughs. Waterflooding was chosen against gas injection to be applied to Field ABX2 to improve recovery after primary production ceased.

Parallel Implementation of the Deterministic Ensemble Kalman Filter for Reservoir History Matching

In this paper, the deterministic ensemble Kalman filter is implemented with a parallel technique of the message passing interface based on our in-house black oil simulator. The implementation is separated into two cases: (1) the ensemble size is greater than the processor number and (2) the ensemble size is smaller than or equal to the processor number. Numerical experiments for estimations of three-phase relative permeabilities represented by power-law models with both known endpoints and unknown endpoints are presented. It is shown that with known endpoints, good estimations can be obtained. With unknown endpoints, good estimations can still be obtained using more observations and a larger ensemble size. Computational time is reported to show that the run time is greatly reduced with more CPU cores. The MPI speedup is over 70% for a small ensemble size and 77% for a large ensemble size with up to 640 CPU cores.

A Graphics Processing Unit–Based, Industrial Grade Compositional Reservoir Simulator

SummaryRecently, graphics processing units (GPUs) have been demonstrated to provide a significant performance benefit for black-oil reservoir simulation, as well as flash calculations that serve an important role in compositional simulation. A comprehensive approach to compositional simulation based on GPUs has yet to emerge, and the question remains as to whether the benefits observed in black-oil simulation persist with a more complex fluid description. We present a positive answer to this question through the extension of a commercial GPU-based black-oil simulator to include a compositional description based on standard cubic equations of state (EOSs). We describe the motivations for the selected nonlinear formulation, including the choice of primary variables and iteration scheme, and support for both fully implicit methods (FIMs) and adaptive implicit methods (AIMs). We then present performance results on an example sector model and simplified synthetic case designed to allow a detailed examination of runtime and memory scaling with respect to the number of hydrocarbon components and model size, as well as the number of processors. We finally show results from two complex asset models (synthetic and real) and examine performance scaling with respect to GPU generation, demonstrating that performance correlates strongly with GPU memory bandwidth.NOTE: This paper is also published as part of the 2021 SPE Reservoir Simulation Conference Special Issue.

A diffusion-based compositionally-extended black oil model to investigate produced gas re-injection EOR in Eagle Ford

In this study, an in-house reduced black oil simulation model is used to investigate cyclic produced gas rejection in Eagle Ford shale formation. Molecular diffusion may play a crucial role in mass transfer in tight shale formations. However, the diffusion has not been incorporated in a black-oil type model in previous studies. In this study, the diffusive term is included into the governing equation and its effect on production performance is examined by using a black oil model. Diffusion coefficients are calculated by using Sigmund correlation, which makes them a function of phase compositions, phase properties, pressure, and temperature. Considering that phase compositions are influenced by large gas-oil capillary pressure nanoconfinement effect, diffusion coefficients are also altered based on this affect. This is the first study that incorporates the large gas-oil capillary pressure effect on diffusion coefficients in nanopores, through using a reduced black oil model. The operation parameters including initial injection time, injection rate, number of cycles are examined. We found that larger injection rates and more number of cycles are efficient in improving the oil recovery. Injection rate is the most crucial parameters in cyclic gas injection approach, followed by cycle numbers. Huff-n-puff results in good efficiency at relatively tight matrix, however, it is not always more efficient for very low permeabilities, as for the very tight formation, the injection gas cannot penetrate to the deeper formation to bring out much more oil from the reservoir in the same “huff” and “soaking” time period. The molecular diffusion plays an important role in gas injection process and cannot be ignored. When nano-confinement effect is included, the diffusion coefficient in gas phase is decreased and the diffusion coefficient in oil phase is increased as pore size decreases, but the effect is not strong especially at relatively high pressures.

Optimizing productivity in oil rims: simulation studies on water and gas injection patterns

Thin oil rim are reservoirs with hydrocarbon pay zone not more than 100 ft. Production challenges mainly water, and gas coning arises due to this trait and presence of a larger gas cap and aquifer. To safely exploit from oil rim reservoirs, the right production choices and optimization of production parameters need to be implemented before the commencement of any recovery scheme. A case study reservoir of an oil rim in the Niger-delta producing region is placed on a concurrent production via 8 horizontal producer wells after history matching and optimization of production parameters using a black oil simulator (Eclipse). Six different pattern scenarios of water and gas injection at 3 rates are considered: optimized oil recovery estimates of 5.43%, 4.51%, 5.41%, 4.93%, 5.89%, and 5.82% for inverted direct line water injection, inverted staggered water injection, inverted 4 spot injection, 5 spot water injection, inverted 7 spot water injection, and inverted 9 spot water injection respectively. The incremental oil recovery over the base case (no injection) recorded in like manner are 1.43%, 0.51%, 1.41%, 0.93%, 1.89%, and 1.82%. The results show that pattern water injection at 1000 stb/day is more suitable for optimum oil recovery for oil rims under concurrent production.

The effect of chemically enhanced oil recovery on thin oil rim reservoirs

Oil rim reservoirs are characterised with a small thickness relative to their overlying gas caps and underlying aquifers and the development these reservoirs are planned very carefully in order to avoid gas and water coning and maximise oil production. Studies have shown low oil recoveries from water and gas injection, and while foam and water alternating gas injections resulted in positive recoveries, it is viewed that an option of an application of chemical enhanced oil recovery option would be preferable. This paper focuses on the application of chemical enhanced oil recovery to improve production from an oil rim reservoir in Niger Delta. Using Eclipse black oil simulator, the effects of surfactant concentration and injection time and surfactant alternating gas are studied on overall oil recovery. Surfactant injections at start and middle of production resulted in a 3.7 MMstb and 3.6 MMstb at surfactant concentration of 1% vol, respectively. This amounted to a 6.6% and 6.5% increment over the base case of no injection. A case study of surfactant alternating gas at the middle of production gave an oil recovery estimate of 10.7%.

New proxy models for predicting oil recovery factor in waterflooded heterogeneous reservoirs

To predict the recovery factor (RF) in waterflooded layered oil reservoirs, two empirical relationships were derived. Both correlations use four independent variables. These are reservoir heterogeneity (characterized by permeability variation coefficient), permeability anisotropy (ratio of vertical to horizontal permeability), viscosity of the injected water, and water injection rate. One of the correlations estimates RF at water breakthrough time (RFBT) and the other evaluates RF at the end of project (RFEOP). Each correlation comes in an expanded form with more parameters and a reduced form with fewer parameters. Both models are based on the global linear model. Eclipse black-oil simulation was used to determine RF for generic reservoirs with different combinations of permeability variation, permeability anisotropy, injected water viscosities, and water injection rates. A total of 192 data sets have been generated. Out of these, 144 data sets (about 75% of the generated sets) were used for model development and 48 data sets (about 25% of the generated sets) were used for model testing and validation. The expanded forms of the new developed correlations gave reliable estimates of RFBT and RFEOP with absolute average percent difference (AAPCD) of 6.9 and 1.02, respectively. The reduced forms yielded slightly higher AAPCDs of 8.30 and 1.04, respectively. When tested against 48 simulation-generated data sets, the expanded forms yielded excellent fits for RFBT and RFEOP with AAPCDs of 14 and 6.5, respectively. The reduced forms showed comparable fit with AAPCDs of 16.9 and 6.70, respectively. The highest RFEOP of 50.6% was achieved for a generic reservoir with a permeability variation in V = 0.1 and a permeability anisotropy of kz/kx = 1.0. This particular reservoir needs to be waterflooded using a water viscosity of µw = 1.0 cp and a water injection rate of qi = 10,000 bpd. Finally, when tested against the Guthrie–Greenberger and the API statistical study, using a single field data set, the proposed correlations gave higher absolute percent difference of 22.9 and 22.7 compared to 0.758 and 19.2 for Guthrie–Greenberger and the API statistical study, respectively.

Numerical modeling and experimental investigation on the effect of low-salinity water flooding for enhanced oil recovery in carbonate reservoirs

Numerous studies concluded that water injection with modified ionic content/salinity in sandstones would enhance the oil recovery factor due to some mechanisms. However, the effects of smart water on carbonated formations are still indeterminate due to a lack of experimental investigations and researches. This study investigates the effects of low-salinity (Low Sal) solutions and its ionic content on interfacial tension (IFT) reduction in one of the southwestern Iranian carbonated reservoirs. A set of organized tests are designed and performed to find each ion’s effects and total dissolved solids (TDS) on the candidate carbonated reservoir. A sequence of wettability and IFT (at reservoir temperature) tests are performed to observe the effects of controlling ions (sulfate, magnesium, calcium, and sodium) and different salinities on the main mechanisms (i.e., wettability alteration and IFT reduction). All IFT tests are performed at reservoir temperature (198 °F) to minimize the difference between reservoir and laboratory-observed alterations. In this paper, the effects of four different ions (SO42-, Ca2+, Mg2+, Na+) and total salinity TDS (40,000, 20,000, 5000 ppm) are investigated. From all obtained results, the best two conditions are applied in core flooding tests to obtain the relative permeability alterations using unsteady-state methods and Cydarex software. The final part is the simulation of the whole process using the Schlumberger Eclipse black oil simulator (E100, Ver. 2010) on the candidate reservoir sector. To conclude, at Low Sal (i.e., 5000 ppm), the sulfate ion increases sulfate concentration lower IFT, while in higher salinities, increasing sulfate ion increases IFT. Also, increasing calcium concentration at high TDS (i.e., 40,000 ppm) decreases the amount of wettability alteration. In comparison, in lower TDS values (20,000 and 5000 ppm), calcium shows a positive effect, and its concentration enhanced the alteration process. Using Low Sal solutions at water cut equal or below 10% lowers recovery rate during simulations while lowering the ultimate recovery of less than 5%.

Optimizing productivity in oil rims: simulation studies on horizontal well placement under simultaneous oil and gas production

Thin oil rim reservoirs are predominantly those with pay thickness of less than 100 ft. Oil production challenges arise due to the nature of the gas cap and aquifer in such reservoirs and well placement with respect to the fluid contacts. Case studies of oil rim reservoir and operational properties from the Niger-Delta region are used to build classic synthetic oil rim models with different reservoir parameters using a design of experiment. The black oil simulation model of the ECLIPSE software is activated with additional reservoir properties and subsequently initialized to estimate initial oil and gas in place. To optimize hydrocarbon production, 2 horizontal wells are initiated, each to concurrently produce oil and gas. Well placements of (0.5 ft., 0.25 ft. and 0.75 ft.) are made with respect to the pay thickness and then to the fluid contacts. The results show that for oil rim with bigger aquifers, an oil recovery of 8.3% is expected when horizontal wells are placed at 0.75 ft. of the pay thickness away from the gas oil contact, 8.1% oil recovery in oil rims with larger gas caps with completions at 0.75 ft. of the pay zone from the gas oil contacts, 6% oil recovery with relatively small gas caps and aquifer and 9.3% from oil rims with large gas caps and aquifers, with completions at mid-stream of the pay zone.

Rastlantısal Parçacık Hareket Yöntemiyle İncelenen Dağılım Katsayısının Polimer Enjeksiyonu Üzerine Etkisi

Polymer injection is a chemical EOR process, where the aim is to improve sweep efficiency of water flooding in an oil reservoir by increasing the water viscosity with the thickening effect of polymer injected with water. A random walk particle tracking model is developed to simulate the injection of polymer into an oil reservoir and it is integrated into an open source black-oil reservoir simulator (SINTEF’s MATLAB Reservoir Simulation Toolbox, MRST). The black-oil simulator solves the set of partial differential equations describing multiphase fluid flow in the porous medium, whereas the transport of the injected polymer due to advection and dispersion processes is obtained from the applied random walk method. The finite difference/finite volume discretizations of the continuity equations applied in MRST does not involve the physical dispersion processes. The dispersion observed on the results are called the numerical dispersion and are due to the numerical discretization methods applied to solve the continuity equations. Since dispersion in porous media is a scale dependent process, it is hard to quantify its coefficient by experiments or empirical equations in general. The random walk method to model the transport of injected polymer in the reservoir is independent of discretization. Hence, it does not involve numerical dispersion. Instead, the physical dispersion due to, for instance, the tortuosity of flow path or the adsorption of polymer in porous media can be included into the model. Therefore, we used the method to analyze the effect of dispersion coefficient. Increased dispersion coefficient causes the results to converge to actual MRST solution with increased uncertainties of polymer concentration. The dispersivity of a reservoir in simple one-dimensional problems can be determined with the method.

Effect of hydrodynamic tilting at fluid contacts to reservoir production performance

Down-flush hydrodynamic movement of fluids at at transitional zones towards areas with low pressure gradients have been reported to directly influence the accurate prediction of petroleum reservoir’s production performances over time. Fluctuations in the fluid-fluid interactions and pressure changes around the reference line was the major cause for the discrepancy. In this research, a sensitivity study on the influence of hydrodynamic tilt factor h to oil, water and gas production was carried-out by means of the commercial software Eclipse Black oil simulator using the openSource Norne field data. The constant h is a function of the corrected shut-in pressure, fluid specific gravity at contact base-lines, pressure at the reference elevation and at the oil-water contact. The error in the contact depth was captured using the difference between the initial and calculated true vertical depths of the fluid’s contact zones. The obtained information was fed into the simulator to model the process dynamics. Findings revealed that the error margin for the first case hA (gas-oil contact) was insignificant. However, a mean deviation in the reservoir’s production predictions of atleast 8% for approximately a 6.5% change in the interacting fluids density was attained in-contrast to the base case.