An Analysis of Numerically Induced Pulses in Simulations of Low-Salinity Waterflooding and Their Reduction by Flow Upscaling

SPE Journal ◽  
2021 ◽  
pp. 1-21
Author(s):  
Hasan Al-Ibadi ◽  
Karl D. Stephen ◽  
Eric Mackay
Keyword(s):  
Oil Recovery ◽  
Flow Behavior ◽  
Scale Up ◽  
Numerical Dispersion ◽  
Salinity Range ◽  
Fractional Flow ◽  
Numerical Errors ◽  
Low Salinity ◽  
Effective Manner ◽  
Courant Condition

Summary Numerical fidelity is required when using simulations to predict enhanced-oil-recovery (EOR) processes. In this paper, we investigate the conditions that lead to numerical errors when simulating low-salinity (LS) waterflooding (LSWF). We also examine how to achieve more accurate simulation results by scaling up the flow behavior in an effective manner. An implicit finite-difference numerical solver was used to simulate LSWF. The accuracy of the numerical solution has been examined as a function of changing the length of the grid cell and the timestep. Previously we have shown that numerical dispersion induces a physical retardation such that the LS front slows down while the formation water front speeds up. We also report for the first time that pulses can be generated as numerical artifacts in coarsely gridded simulations of LSWF. These effects reflect the interaction of dispersion, the effective-salinity range, and the use of upstream weighting during calculation, and can corrupt predictions of flow behavior. The effect of the size of the timestep was analyzed with respect to the Courant condition, traditionally related to explicit numerical schemes and also numerical stability conditions. We also investigated some of the nonlinear elements of the simulation model, such as the differences between the concentrations of connate water salinity and the injected brine, effective-salinity-concentration range, and the net mobility change on fluids through changing the salinity. We report that to avoid pulses it is necessary, but not sufficient, to meet the Courant condition relating timestep size to cell size. We have also developed two approaches that can be used to scale up simulations of LSWF and tackle the numerical problems. The first method is dependent on a mathematical relationship between the fractional flow, effective-salinity range, and the Péclet number and treats the effective-salinity range as a pseudofunction. The second method establishes an unconventional proxy method equivalent to pseudorelative permeabilities. A single table of pseudorelative permeability data can be used for a waterflood instead of two tables, as is usual for LSWF. This is a novel approach that removes the need for relative permeability interpolation during the simulation. Overall, by avoiding numerical errors, we help engineers to more efficiently and accurately assess the potential for improving oil recovery using LSWF and thus optimize field development. We also avoid the numerical pulses inherent in the traditional LSWF model.

Extended Fractional-Flow Model of Low-Salinity Waterflooding Accounting for Dispersion and Effective Salinity Range

SPE Journal ◽  
2019 ◽  
Vol 24 (06) ◽  
pp. 2874-2888 ◽  
Author(s):  
Hasan Al–Ibadi ◽  
Karl D. Stephen ◽  
Eric J. Mackay
Keyword(s):  
Relative Permeability ◽  
Flow Behavior ◽  
Flow Analysis ◽  
Salinity Range ◽  
Fractional Flow ◽  
Low Salinity ◽  
Low Salinity Water ◽  
Low Salinity Waterflooding ◽  
Salinity Water ◽  
The Impact

Summary Low–salinity waterflooding (LSWF) is an emergent technology developed to increase oil recovery. Laboratory–scale testing of this process is common, but modeling at the production scale is less well–reported. Various descriptions of the functional relationship between salinity and relative permeability have been presented in the literature, with respect to the differences in the effective salinity range over which the mechanisms occur. In this paper, we focus on these properties and their impact on fractional flow of LSWF at the reservoir scale. We present numerical observations that characterize flow behavior accounting for dispersion. We analyzed linear and nonlinear functions relating salinity to relative permeability and various effective salinity ranges using a numerical simulator. We analyzed the effect of numerical and physical dispersion of salinity on the velocity of the waterflood fronts as an expansion of fractional–flow theory, which normally assumes shock–like behavior of water and concentration fronts. We observed that dispersion of the salinity profile affects the fractional–flow behavior depending on the effective salinity range. The simulator solution is equal to analytical predictions from fractional–flow analysis when the midpoint of the effective salinity range lies between the formation and injected salinities. However, retardation behavior similar to the effect of adsorption occurs when these midpoint concentrations are not coincidental. This alters the velocities of high– and low–salinity water fronts. We derived an extended form of the fractional–flow analysis to include the impact of salinity dispersion. A new factor quantifies a physical or numerical retardation that occurs. We can now modify the effects that dispersion has on the breakthrough times of high– and low–salinity water fronts during LSWF. This improves predictive ability and also reduces the requirement for full simulation.

Scaling Up Low-Salinity Waterflooding in Heterogenous Reservoirs

SPE Journal ◽  
2021 ◽  
pp. 1-22
Author(s):  
Hasan Al-Ibadi ◽  
Karl Stephen ◽  
Eric Mackay
Keyword(s):  
Relative Permeability ◽  
Coarse Grid ◽  
Numerical Dispersion ◽  
Absolute Permeability ◽  
Scale Model ◽  
Salinity Range ◽  
Fine Scale ◽  
Fractional Flow ◽  
Low Salinity ◽  
Low Salinity Waterflooding

SummaryModeling the dynamic fluid behavior of low-salinity waterflooding (LSWF) at the reservoir scale is a challenge that requires a coarse-grid simulation to enable prediction in a feasible time scale. However, evidence shows that using low-resolution models will result in a considerable mismatch compared with an equivalent fine-scale model with the potential of strong, numerically induced pulses and other dispersion-related effects. This work examines two new upscaling methods that have been applied to improve the accuracy of predictions in a heterogeneous reservoir where viscous crossflow takes place.We apply two approaches to upscaling to bring the flow prediction closer to being exact. In the first method, we shift the effective-salinity range for the coarse model using algorithms that we have developed to correct for numerical dispersion and associated effects. The second upscaling method uses appropriately derived pseudorelative permeability curves. The shape of these new curves is designed using a modified fractional-flow analysis of LSWF that captures the relationship between dispersion and the waterfront velocities. This second approach removes the need for explicit simulation of salinity transport to model oil displacement. We applied these approaches in layered models and for permeability distributed as a correlated random field.Upscaling by shifting the effective-salinity range of the coarse-grid model gave a good match to the fine-scale scenario, while considerable mismatch was observed for upscaling of the absolute permeability alone. For highly coarsened models, this method of upscaling reduced the appearance of numerically induced pulses. On the other hand, upscaling by using a single (pseudo)relative permeability produced more robust results with a very promising match to the fine-scale scenario. These methods of upscaling showed promising results when they were used to scale up fully communicating and noncommunicating layers as well as models with randomly correlated permeability.Unlike documented methods in the literature, these newly derived methods take into account the substantial effects of numerical dispersion and effective concentration on fluid dynamics using mathematical tools. The methods could be applied for other models where the phase mobilities change as a result of an injected solute, such as surfactant flooding and alkaline flooding. Usually these models use two sets of relative permeability and switch from one to another as a function of the concentration of the solute.

Numerical effects on the simulation of surfactant flooding for enhanced oil recovery

2021 ◽  
Author(s):  
Olaitan Akinyele ◽  
Karl D. Stephen
Keyword(s):  
Interfacial Tension ◽  
Cell Size ◽  
Oil Recovery ◽  
Flow In Porous Media ◽  
Numerical Dispersion ◽  
Sharp Change ◽  
Surfactant Flooding ◽  
Fractional Flow ◽  
Time Step ◽  
Scale Models

Abstract Numerical simulation of surfactant flooding using conventional reservoir simulation models can lead to unreliable forecasts and bad decisions due to the appearance of numerical effects. The simulations give approximate solutions to systems of nonlinear partial differential equations describing the physical behavior of surfactant flooding by combining multiphase flow in porous media with surfactant transport. The approximations are made by discretization of time and space which can lead to spurious pulses or deviations in the model outcome. In this work, the black oil model was simulated using the decoupled implicit method for various conditions of reservoir scale models to investigate behaviour in comparison with the analytical solution obtained from fractional flow theory. We investigated changes to cell size and time step as well as the properties of the surfactant and how it affects miscibility and flow. The main aim of this study was to understand pulse like behavior that has been observed in the water bank to identify cause and associated conditions. We report for the first time that the pulses occur in association with the simulated surfactant water flood front and are induced by a sharp change in relative permeability as the interfacial tension changes. Pulses are diminished when the adsorption rate was within the value of 0.0002kg/kg to 0.0005kg/kg. The pulses are absent for high resolution model of 5000 cells in x direction with a typical cell size as used in well-scale models. The growth or damping of these pulses may vary from case to case but in this instance was a result of the combined impact of relative mobility, numerical dispersion, interfacial tension and miscibility. Oil recovery under the numerical problems reduced the performance of the flood, due to large amounts of pulses produced. Thus, it is important to improve existing models and use appropriate guidelines to stop oscillations and remove errors.

Novel Observations of Salinity Transport in Low-Salinity Waterflooding

SPE Journal ◽  
2019 ◽  
Vol 24 (03) ◽  
pp. 1108-1122 ◽  
Author(s):  
Hasan Al-Ibadi ◽  
Karl Stephen ◽  
Eric Mackay
Keyword(s):  
Analytical Solution ◽  
Weighting Function ◽  
Numerical Dispersion ◽  
Salinity Range ◽  
Low Salinity ◽  
Salinity Profile ◽  
Salinity Transport ◽  
Advection Term ◽  
Input Parameters ◽  
Low Salinity Waterflooding

Summary Low-salinity waterflooding (LSWF) is a promising process that could lead to increased oil recovery. To date, the greatest attention has been paid to the complex oil/water/rock chemical reactions that might explain the mechanisms of LSWF, and it is generally accepted that these result in behavior equivalent to changing oil and water mobility. This behavior is modeled using an effective salinity range and weighting function to gradually switch from high- to low-salinity relative permeability curves. There has been limited attention on physical transport of fluids during LSWF, particularly at large scale. We focus on how the salinity profile interacts with water fronts through the effective salinity range and dispersion to alter the transport behavior and change the flow velocities, particularly for the salinity profile. We examined a numerical simulation of LSWF at the reservoir scale. Various representations of the effective salinity range and weighting function were also examined. The dispersion of salinity was compared with a theoretical form of numerical dispersion based on input parameters. We also compared salinity movement with the analytical solution of the conventional dispersion/advection equation. From simulations we observed that salinity is dispersed as analytically predicted, although the advection velocity might be changed. In advection-dominated flow, the salinity profile moves at the speed of the injected water. However, as dispersion increases, the mixing zone falls under the influence of the faster-moving formation water and, thus, speeds up. To predict the salinity profile theoretically, we have modified the advection term of the analytical solution as a function of the formation- and injected-water velocities, Péclet number, and effective salinity range. This important result enables prediction of the salinity transport by this newly derived modification of the analytical solution for 1D flow. We can understand the correction to the flow behavior and quantify it from the model input parameters. At the reservoir scale, we typically simulate flow on coarse grids, which introduces numerical dispersion or must include physical dispersion from underlying heterogeneity. Corrections to the equations can contribute to improving the precision of the coarse-scale models, and, more generally, the suggested form of the correction can also be used to calculate the movement of any solute that transports across an interface between two mobile fluids. We can also better understand the relative behaviors of passive tracers and those that are adsorbed.

Pore-Scale Simulation of the Interplay between Wettability, Capillary Number, and Salt Dispersion on the Efficiency of Oil Mobilization by Low-Salinity Waterflooding

SPE Journal ◽  
2021 ◽  
pp. 1-22
Author(s):  
Arman Namaee-Ghasemi ◽  
Shahab Ayatollahi ◽  
Hassan Mahani
Keyword(s):  
Capillary Pressure ◽  
Oil Recovery ◽  
Capillary Number ◽  
Salinity Range ◽  
Pore Geometry ◽  
Side Channel ◽  
Dispersion Pattern ◽  
Pore Scale ◽  
Low Salinity ◽  
Low Salinity Waterflooding

Summary Nonuniform mixing during low-salinity waterflooding (LSWF) is a function of the pore geometry and flow patterns within the porous system. Salinity-dependent wettability alteration (WA) changes the entry capillary pressure, which may mobilize the trapped oil depending on the flow regime and salt dispersion pattern. The complex interplay between the wettability, capillary number (NCa), and salt dispersion caused by pore-scale heterogeneity on the efficiency of LSWF is not well understood. In this paper, direct numerical simulations in a pore-doublet model (PDM) were carried out with OpenFOAM® (OpenCFD, Berkshire, UK) using the volume-of-fluid (VOF) method. Oil trapping and remobilization were studied at relevant NCa as low as 10−6 under different initial wettability states. Depending on the effective salinity ranges (ESRs) for the low-salinity effect (LSE), three WA models were implemented, and the effects of WA degree and salinity distribution on LSWF flow dynamics were investigated. The slow process of WA by means of thin film phenomena was captured by considering a diffuse interface at the three-phase contact line. Because of the pore structure of the pore doublet, only in nonwater-wet cases, oil is trapped in the narrower side channel (NSC) after high-salinity waterflooding (HSWF) and may be remobilized by LSWF. In strongly oil-wet cases, oil is recovered gradually by LSWF by means of a film-flow mechanism near the outlet. In moderately oil-wet cases, however, the entire trapped oil ganglion can be mobilized, provided that the entry capillary pressure is sufficiently reduced. The degree of WA, ESR, kinetics of WA, and the wettability of pore surface at the outlet are determining factors in the drainage of the trapped oil. The salt dispersion pattern in the flowing region [i.e., wider side channel (WSC)] controls the wettability distribution and the rate and magnitude of oil recovery from the stagnant region (i.e., NSC). The difference between the WA models is more apparent near the outlet, where the salinity profile is more dispersed. The ESR in which WA occurs determines the speed of the entry capillary pressure reduction and, thus, the recovery factor. In cases where WA occurs at a salinity threshold (ST), the highest recovery is obtained, whereas with the full-salinity-range WA model, the oil recovery performance is lowest. From the capillary desaturation perspective, it is found that the LSE becomes more pronounced when NCa is less than 10−5, and the dispersion regime is in the power-law interval. Because the adverse effect of salt dispersion in the flowing region is delayed, the LSE is intensified. For the simulations to be representative of the actual conditions in the porous medium, much lower NCa than currently used in many research works must be studied. Otherwise, the simulations may lead to over- or underestimation of the LSE. The synergetic or antagonistic effects caused by the interplay between viscous and capillary forces and dispersion may lead to total recovery or entrapment of oil, regardless of WA. Based on the pore geometry, initial wettability state, and balance of forces, the mobilized oil may flow past the conjunction (favorable) or in the backward direction (unfavorable) to the WSC and get retrapped. Successful drainage of oil from the pore system after WA is essential for observing incremental oil recovery by LSWF.

scholarly journals A Single-Well Gas-Assisted Gravity Drainage Enhanced Oil Recovery Process for U.S. Deepwater Gulf of Mexico Operations

Energies ◽  
2021 ◽  
Vol 14 (6) ◽  
pp. 1743
Author(s):  
Bikash D. Saikia ◽  
Dandina N. Rao
Keyword(s):  
Gulf Of Mexico ◽  
Enhanced Oil Recovery ◽  
Oil Recovery ◽  
Scale Up ◽  
Cost Effective ◽  
Recovery Process ◽  
Recovery Factor ◽  
Gravity Drainage ◽  
Effective Manner ◽  
Single Well

The U.S. Deepwater Gulf of Mexico (DGOM) area that has some of the most prolific oil reservoirs is still awaiting the development of a viable enhanced oil recovery (EOR) process. Without it, DGOM will remain severely untapped. Exorbitant well costs, in excess of $200 million, preclude having extensive injection patterns, commonly used in EOR design frameworks. Aside from injection patterns, even operationally waterflooding has met with significant challenges because of injectivity issues in these over pressurized turbidities. The gas-assisted gravity drainage (GAGD) EOR process, that holds promise for deepwater environments because of lesser injectivity issues, among others, has been adapted in this work to overcome these limitations. A novel design in the form of a single well—gas assisted gravity drainage (SW-GAGD) process, has been demonstrated to emulate the benefits of a GAGD process in a cost-effective manner. Unlike conventional GAGD processes, which need multiple injectors and separate horizontal production wells, the SW-GAGD process just uses a single well for injection and well production. The performance of the process has been established using partially scaled visual glass models based on dimensional analyses for scale up of the process. The recovery factor has been shown to be in the range of 65–80% in the immiscible mode alone, and the process is orders of magnitude faster than natural gravity drainage. A toe-to-heel configuration of the SW-GAGD process has also been tested and for the configuration to be immune from reservoir layering, the toe of the well should ideally end at the top of the payzone. Better sweep of the payzone and consequent high recovery factor of 80% OOIP was observed, if the heel part of the bottom lateral is located in a lower permeability zone.

Capturing the Effect of Fracture Heterogeneity on Multiphase Flow During Fluid Injection

2013 ◽  
Vol 16 (02) ◽  
pp. 194-208 ◽  
Author(s):  
S.. Jonoud ◽  
O.P.. P. Wennberg ◽  
G.. Casini ◽  
J.A.. A. Larsen
Keyword(s):  
Fluid Flow ◽  
Multiphase Flow ◽  
Oil Recovery ◽  
Large Scale ◽  
Flow Behavior ◽  
Fractured Reservoirs ◽  
Scale Up ◽  
Carbonate Reservoir ◽  
Fracture Model ◽  
Dynamic Simulations

Summary Carbonate fractured reservoirs introduce a tremendous challenge to the upscaling of both single- and multiphase flow. The complexity comes from both heterogeneous matrix and fracture systems in which the separation of scales is very difficult. The mathematical upscaling techniques, derived from representative elementary volume (REV), must therefore be replaced by a more realistic geology-based approach. In the case of multiphase flow, an evaluation of the main forces acting during oil recovery must also be performed. A matrix-sector model from a highly heterogeneous carbonate reservoir is linked to different fracture realizations in dual-continuum simulations. An integrated iterative workflow between the geology-based static modeling and the dynamic simulations is used to investigate the effect of fracture heterogeneity on multiphase fluid flow. Heterogeneities at various scales (i.e., diffuse fractures and subseismic faults) are considered. The diffuse-fracture model is built on the basis of facies and porosity from the matrix model together with core data, image-log data, and data from outcrop-analogs. Because of poor seismic data, the subseismic-fault model is mainly conceptual and is based on the analysis of outcrop-analog data. Fluid-flow simulations are run for both single-phase and multiphase flow and gas and water injections. A better understanding of fractured-reservoirs behavior is achieved by incorporating realistic fracture heterogeneity into the geological model and analyzing the dynamic impact of fractures at various scales. In the case of diffuse fractures, the heterogeneity effect can be captured in the upscaled model. The subseismic faults, however, must be explicitly represented, unless the sigma (shape) factor is included in the upscaling process. A local grid-refinement approach is applied to demonstrate explicit fractures in large-scale simulation grids. This study provides guidelines on how to effectively scale up a heterogeneous fracture model and still capture the heterogeneous flow behavior.

scholarly journals Semi-Analytical Solution of Chemical Flooding in Heterogeneous Non-Communicating Layers with a Focus on Low Salinity Water Flooding

2020 ◽  
Vol 135 (1) ◽  
pp. 101-135
Author(s):  
Hasan Al-Ibadi ◽  
Karl D. Stephen ◽  
Eric J. Mackay
Keyword(s):  
Analytical Solutions ◽  
Water Flooding ◽  
Salinity Range ◽  
Chemical Flooding ◽  
Fractional Flow ◽  
Sweep Efficiency ◽  
Flow Equations ◽  
Low Salinity ◽  
Low Salinity Water ◽  
Salinity Water

Abstract Chemical flooding has been implemented intensively for some years to enhance sweep efficiency in porous media. Low salinity water flooding (LSWF) is one such method that has become increasingly attractive. Historically, analytical solutions were developed for the flow equations for water flooding conditions, particularly for non-communicating strata. We extend these to chemical flooding, more generally, and in particular for LSWF where salinity is modeled as an active tracer and changes relative permeability. Dispersion affects the solutions, and we include this also. Using fractional flow theory, we derive a mathematical solution to the flow equations for a set of layers to predict fluid flow and solute transport. Analytical solutions tell us the location of the lead (formation) waterfront in each layer. We extend a correlation that we previously developed to predict the effects of numerical and physical dispersion. We used this correction to predict the location of the second waterfront in each layer which is induced by the chemical’s effect on mobility. We show that in multiple non-communicating layers, mass conservation can be used to deduce the interlayer relationships of the various fronts that form. This is based on similar analysis developed for water flooding although the calculations are more complex because of the development of multiple fronts. The result is a predictive tool that we compare to numerical simulations and the precision is very good. Layers with contrasting petrophysical properties and wettability are considered. We also investigate the relationship between the fractional flow, effective salinity range, salinity dispersion and salinity retardation. The recovery factor and vertical sweep efficiency are also very predictable. The work can also be applicable to other chemical EOR processes if they alter the fluid mobility. This includes polymer and surfactant flooding.

scholarly journals Flow Dynamics of Sulfate-Modified Water/Polymer Flooding in Micromodels with Modified Wettability

2020 ◽  
Vol 10 (9) ◽  
pp. 3239 ◽  
Author(s):  
Muhammad Tahir ◽  
Rafael E. Hincapie ◽  
Calvin L. Gaol ◽  
Stefanie Säfken ◽  
Leonhard Ganzer
Keyword(s):  
Oil Recovery ◽  
Flow Behavior ◽  
Water Flooding ◽  
Process Efficiency ◽  
Pore Scale ◽  
Low Salinity ◽  
Low Salinity Water ◽  
Salinity Water ◽  
Core Flood ◽  
Fluid Interaction

This work describes the flow behavior of the oil recovery obtained by the injection of sulfate-modified/low-salinity water in micromodels with different wettabilities. It provides a detailed microscopic visualization of the displacement taking place during modified water flooding at a pore-scale level, while evaluating the effect of wettability on oil recovery. A comprehensive workflow for the evaluation is proposed that includes fluid–fluid and rock–fluid interactions. The methods studied comprise flooding experiments with micromodels. Artificial and real structure water-wet micromodels are used to understand flow behavior and oil recovery. Subsequently, water-wet, complex-wet, and oil-wet micromodels help understand wettability and rock–fluid interaction. The effect of the sulfate content present in the brine is a key variable in this work. The results of micromodel experiments conducted in this work indicate that sulfate-modified water flooding performs better in mixed-wet/oil-wet (artificial structure) than in water-wet systems. This slightly differs from observations of core flood experiments, where oil-wet conditions provided better process efficiency. As an overall result, sulfate-modified water flooding recovered more oil than SSW injection in oil-wet and complex-wet systems compared to water-wet systems.

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