Frank, Florian (Rice University) | Liu, Chen (Rice University) | Alpak, Faruk O. (Shell International Exploration and Production) | Berg, Steffen (Rice University) | Riviere, Beatrice (Shell Global Solutions International)
Advances in pore-scale imaging, increasing availability of computational resources, and developments in numerical algorithms have started rendering direct pore-scale numerical simulations of multiphase flow on pore structures feasible. In this paper, we describe a two-phase-flow simulator that solves mass- and momentum-balance equations valid at the pore scale (i.e., at scales where the Darcy velocity homogenization starts to break down). The simulator is one of the key components of a molecule-to-reservoir truly multiscale modeling work flow.
A Helmholtz free-energy-driven, thermodynamically based diffuse-interface/phase-field method is used for the effective simulation of numerous advecting interfaces, while honoring the interfacial tension (IFT). The advective Cahn-Hilliard (CH) (mass-balance, energy dissipation) and Navier-Stokes (NS) (momentum-balance, incompressibility) equations are coupled to each other within the phase-field framework. Wettability on rock/fluid interfaces is accounted for by means of an energy-penalty-based wetting (contact-angle) boundary condition. Individual balance equations are discretized by use of a flexible discontinuous Galerkin (DG) method. The discretization of the mass-balance equation is semi-implicit in time using a convex/concave splitting of the energy term. The momentum-balance equation is split from the incompressibility constraint by a projection method and linearized with a Picard splitting. Mass- and momentum-balance equations are coupled to each other by means of operator splitting, and are solved sequentially.
We discuss the mathematical model and its DG discretization, and briefly introduce nonlinear and linear solution strategies. Numerical-validation tests show optimal convergence rates for the DG discretization, indicating the correctness of the numerical scheme and its implementation. Physical-validation tests demonstrate the consistency of the phase distribution and velocity fields simulated within our framework. Finally, two-phase-flow simulations on two real pore-scale images demonstrate the usefulness of the pore-scale simulator. The direct pore-scale numerical-simulation methodology rigorously considers the flow physics by directly acting on pore-scale images of rocks without remeshing. The proposed method is accurate, numerically robust, and exhibits the potential for tackling realistic problems.
Bartels, Willem-Bart (Utrecht University) | Mahani, Hassan (Shell Global Solutions International B.V.) | Berg, Steffen (Shell Global Solutions International B.V.) | Menezes, Robin (Delft University of Technology) | van der Hoeven, Jesse A. (Utrecht University) | Fadili, Ali (Shell Global Solutions International B.V.)
Low-salinity waterflooding (LSF) is receiving increased interest as a promising method to improve oil-recovery efficiency. Most of the literature agrees that, on the Darcy scale, LSF can be regarded as a wettability-modification process, leading to a more-water-wet state, although no consensus on the microscopic mechanisms has been reached. To establish a link between the pore-scale and the Darcy-scale description, the flow dynamic at an intermediate scale--i.e., networks of multiple pores--should be investigated. One of the main challenges in addressing phenomena on this scale is to design a model system representative of natural rock. The model system should allow for a systematic investigation of influencing parameters with pore-scale resolution while simultaneously being large enough to capture larger-length-scale effects such as saturation changes and the mobilization and connection of oil ganglia.
In this paper, we use micromodels functionalized with active clay minerals as a model system to study the low-salinity effect (LSE) on the pore scale. A new method was devised to deposit clays in the micromodel. Clay suspensions were made by mixing natural clays (montmorillonite) with isopropyl alcohol (IPA) and were injected into optically transparent 2D glass micromodels. After drying the models, the clay particles were deposited and stick naturally to the glass surfaces. The micromodel was then used to investigate the dependence of the LSE on the type of oil (crude oil vs. n-decane), the presence of clay particles, and aging.
Our results show that the system is responsive to low-salinity brine as the effective contact angle of crude oil shifts toward a more-water-wetting state when brine salinity is reduced. When using n-decane as a reference case of inert oil, no change in contact angle occurred after a reduction in brine salinity.
This responsiveness in terms of contact angle does not necessarily mean that more oil is recovered. Only in the cases where the contact-angle change (because of low-salinity exposure) led to release of oil and reconnection with oil of adjacent pore bodies did the oil become mobile and the oil saturation effectively reduce. This makes contact-angle changes a necessary but not sufficient requirement for incremental recovery by LSF. Interestingly, the wettability modification was observed in the absence of clay. Osmosis and interfacial tension (IFT) change were found not to be the primary driving mechanisms of the low-salinity response.
Mahani, Hassan (Shell Global Solutions International B.V.) | Keya, Arsene Levy (Shell Global Solutions International B.V.) | Berg, Steffen (Shell Global Solutions International B.V.) | Nasralla, Ramez (Shell Global Solutions International B.V.)
Laboratory studies have shown that wettability of carbonate rock can be altered to a less-oil-wetting state by manipulation of brine composition and reduction of salinity. Our recent study (Mahani et al. 2015b) suggests that surface-charge alteration is likely to be the driving mechanism of the low-salinity effect in carbonates. Various studies have already established the sensitivity of carbonate-surface charge to brine salinity, pH value, and potential-determining ions in brines. However, in the majority of the studies, single-salt brines or model-carbonate rocks have been used and it is fairly unclear how natural rock reacts to reservoir-relevant brine as well as successive brine dilution; whether different types of carbonate-reservoir rocks exhibit different electrokinetic properties; and how the surface-charge behavior obtained at different brine salinities and pH values can be explained.
This paper presents a comparative study aimed at gaining more insight into the electrokinetics of different types of carbonate rock. This is achieved by ζ-potential measurements on Iceland spar calcite and three reservoir-related rocks—Middle Eastern limestone, Stevns Klint chalk, and Silurian dolomite outcrop—over a wide range of salinity, brine composition, and pH values. With a view to arriving at a more-tractable approach, a surface-complexation model (SCM) implemented in PHREEQC software (Parkhurst and Appelo 2013) is developed to relate our understanding of the surface reactions to measured ζ-potentials.
It was found that regardless of the rock type, the trends of ζ-potentials with salinity and pH are quite similar. For all cases, the surface charge was found to be positive in high-salinity formation water (FW), which should favor oil-wetting. The ζ-potential successively decreased toward negative values when the brine salinity was lowered to seawater (SW) level and diluted SW. At all salinities, the ζ-potential showed a strong dependence on pH, with positive slope that remained so even with excessive dilution. The sensitivity of the ζ-potential to pH change was often higher at lower salinities.
The existing SCMs cannot predict the observed increase of ζ-potential with pH; therefore, a new model is proposed to capture this feature. According to modeling results, formation of surface species, particularly >CaSO–4 and to a lower extent >CO3Ca+ and >CO3Mg+, strongly influence the total surface charge. Increasing the pH turns the negatively charged moiety >CaSO–4 into both negatively charged >CaCO–3 and neutral >CaOH entities. (Note that throughout this paper, the symbol > indicates surface complexes.) This substitution reduces the negative charge of the surface. The surface concentration of >CO3Ca+ and >CO3Mg+ moieties changes little with change of pH.
Nevertheless, besides similarities in ζ-potential trends, there exist notable differences in terms of magnitude and the isoelectric point (IEP), even between carbonates that are mainly composed of calcite. Among all the samples, chalk particles exhibited the most negative surface charges, followed by limestone. In contrast to this, dolomite particles showed the most positive ζ-potential, followed by calcite crystal. Overall, chalk particles exhibited the highest surface reactivity to pH and salinity change, whereas dolomite particles showed the lowest.
Mahani, Hassan (Shell Global Solutions International B.V.) | Keya, Arsene Levy (Shell Global Solutions International B.V.) | Berg, Steffen (Shell Global Solutions International B.V.) | Nasralla, Ramez (Shell Global Solutions International B.V.)
Laboratory studies have shown that wettability of carbonate rock can be altered to a less oil-wetting state by manipulation of brine composition and reduction of salinity. Our recent study (see
This paper presents a comparative study aimed at gaining more insights into the electrokinetics of different types of carbonate rock. This is achieved by zeta-potential measurements on Iceland spar calcite and three reservoir-related rocks – middle-eastern limestone, Stevns Klint chalk and Silurian dolomite outcrop – over a wide range of salinity, brine composition and pH. With a view to arriving at a more tractable approach, a surface complexation model implemented in PHREEQC is developed to relate our understanding of the surface reactions to measured zeta-potentials.
The trends in the relationships between zeta-potentials on one hand and salinity and pH on the other were quite similar for different types of rock. For all cases, the surface-charge was found to be positive in high-salinity formation water, which should increase oil-wetting. The zeta-potential successively decreased towards negative values when the brine salinity was lowered to seawater level and diluted seawater. At all salinities, the zeta-potential showed a strong dependence on pH, with positive slope with pH which remained so even with excessive dilution. The sensitivity of the zeta-potential to pH-change was often higher at lower salinities.
The increase of zeta-potential with pH is consistent with the results of the surface complexation model, which indicate that formation of surface species, particularly >CaSO4- and to a lower extent >CO3Ca+ and >CO3Mg+, strongly influence the total surface charge. Increasing the pH turns the negatively charged moiety >CaSO4- into both negatively charged >CaCO3- and neutral >CaOHº entities. This substitution reduces the negative charge of the surface. The surface concentration of >CO3Ca+ and >CO3Mg+ moieties changes little with change of pH.
Besides these similarities, there exist notable differences even between carbonates that are mainly composed of calcite. Amongst all the samples, chalk particles exhibited the most negative surface charges, followed by limestone. In contrast to this, dolomite particles showed the most positive zeta-potential, followed by calcite crystal. Overall, chalk particles exhibited the highest surface reactivity to pH and salinity change, while dolomite particles showed the lowest.
Mahani, Hassan (Shell Global Solutions International B.V.) | Keya, Arsene L. (Shell Global Solutions International B.V.) | Berg, Steffen (University of Utrecht) | Bartels, Willem-Bart (Shell Global Solutions International B.V.) | Nasralla, Ramez (Delft University of Technology) | Rossen, William
Several studies conducted mainly on the laboratory scale indicate that in carbonate rocks oil displacement can be influenced by the ionic composition of the brine, providing an opportunity to improve recovery by optimizing the brine mixture used in secondary or tertiary recovery. In industry this topic has been termed "low salinity flooding (LSF) in carbonates" while the underlying mechanisms are not very well understood. The increased oil recovery has been attributed to wettability alteration to a more water-wet state. However, in some studies a positive low salinity effect (LSE) has been ascribed to dissolution of rock, which occurs on the laboratory scale but due to equilibration of brine with carbonate minerals on larger length scales this is not relevant for the reservoir scale. Therefore, the objective of this paper is to gain a better understanding of the underlying mechanism(s) and investigate whether calcite dissolution is the primary mechanism of the LSE.
We used a model system where the contact angle of crude oil deposited on planar surfaces coated with crushed carbonate rock particles was monitored as a function of brine composition. The approach is similar to the one published in
It was observed that by switching from formation water (FW) to seawater (SW), diluted seawater (dSW) and diluted seawater equilibrated with calcite (dSWEQ), the limestone surface became less oil-wet reflected in contact angle decrease. The recession of the 3-phase contact line observed for both SW and dSWEQ, which are not impacted by dissolution, suggests that the LSE occurs even in the absence of mineral dissolution. The trends observed for the zeta-potential data on brine composition clearly support the surface-charge-change mechanism for limestone, where at lower salinities the charges at the limestone-brine interface become more negative, causing lower adhesion or even repulsion between oil and rock.
Dolomite rock shows a different behavior. First, there is a much smaller response in terms of contact angle change. Also, the zeta-potential of dolomite shows generally more positive charges at higher salinities and less decrease at lower salinities, where in comparison to limestone the electrostatic interaction remains attractive or becomes only weakly repulsive.
In summary we conclude that a positive LSE in carbonate rock exists without any dissolution and it is driven by the brine composition dependency of electrostatic interactions between crude oil and rock. However, the magnitude of the LSE is impacted by the mineralogy of carbonate material.
Mahani, Hassan (Shell Global Solutions International B.V.) | Berg, Steffen (Shell Global Solutions International B.V.) | Ilic, Denis (Technische Hogeschool Rijswijk) | Bartels, Willem-Bart (University of Utrecht) | Joekar-Niasar, Vahid (Shell Global Solutions International B.V.)
Low-salinity waterflooding (LSF) is one of the least-understood enhanced-oil-recovery (EOR)/improved-oil-recovery (IOR) methods, and proper understanding of the mechanism(s) leading to oil recovery in this process is needed. However, the intrinsic complexity of the process makes fundamental understanding of the underlying mechanism(s) and the interpretation of laboratory experiments difficult. Therefore, we use a model system for sandstone rock of reduced complexity that consists of clay minerals (Na-montmorillonite) deposited on a glass substrate and covered with crude-oil droplets and in which different effects can be separated to increase our fundamental understanding. We focus particularly on the kinetics of oil detachment when exposed to low-salinity (LS) brine. The system is equilibrated first under high-salinity (HS) brine and then exposed to brines of varying (lower) salinity while the shape of the oil droplets is continuously monitored at high resolution, allowing for a detailed analysis of the contact angle and the contact area as a function of time. It is observed that the contact angle and contact area of oil with the substrate reach a stable equilibrium at HS brine and show a clear response to the LS brine toward less-oil-wetting conditions and ultimately detachment from the clay substrate. This behavior is characterized by the motion of the three-phase (oil/water/solid) contact line that is initially pinned by clay particles at HS conditions, and pinning decreases upon exposure to LS brine. This leads to a decrease in contact area and contact angle that indicates wettability alteration toward a more-water-wet state. When the contact angle reaches a critical value at approximately 40 to 50°, oil starts to detach from the clay. During detachment, most of the oil is released, but in some cases a small amount of oil residue is left behind on the clay substrate. Our results for different salinity levels indicate that the kinetics of this wettability change correlates with a simple buoyancy- over adhesion-force balance and has a time constant of hours to days (i.e., it takes longer than commonly assumed). The unexpectedly long time constant, longer than expected by diffusion alone, is compatible with an electrokinetic ion-transport model (Nernst-Planck equation) in the thin water film between oil and clay. Alternatively, one could explain the observations only by more-specific [non-Derjaguin–Landau–Verwey–Overbeek (DLVO) type] interactions between oil and clay such as cation-bridging, direct chemical bonds, or acid/base effects that tend to pin the contact line. The findings provide new insights into the (sub) pore-scale mechanism of LSF, and one can use them as the basis for upscaling to, for example, pore-network scale and higher scales (e.g., core scale) to assess the impact of the slow kinetics on the time scale of an LSF response on macroscopic scales.
Mahani, Hassan (Shell Global Solutions International B.V.) | Berg, Steffen (Shell Global Solutions International BV) | Ilic, Denis (De Haagse Hoogschool) | Bartels, Willem-Bart (Utrecht University) | Joekar-Niasar, Vahid (Shell Global Solution International BV)
Low salinity waterflooding (LSF) provides an opportunity for improved oil recovery. However the complexity of the process makes both the fundamental understanding of the underlying mechanism(s) and the interpretation of laboratory experiments difficult. Therefore we use a model system for sandstone which consists of clay minerals deposited on a glass substrate and covered with crude oil droplets in order to study the kinetics of oil detachment when exposed to low salinity brine. The system is equilibrated first under high saline brine and then exposed to brines of varying (lower) salinity while the shape of the oil droplets is continuously monitored at high resolution allowing for a detailed analysis of the contact angle and the contact area as a function of time.
We observe that the contact angle and contact area of oil with the substrate reach a stable equilibrium at high saline brine and show a clear response to the low salinity brine towards less oil wetting conditions and ultimately detachment from the clay (Na-montmorillonite) substrate. This behavior is characterized by the motion of the 3-phase (oil-water-solid) contact line which is initially pinned by clay particles at high salinity conditions and that pinning decreases upon exposure to low salinity brine leading to a decrease in contact area and contact angle which indicates wettability alteration towards a more water-wet state. When the contact angle reaches a critical value around 40-50°, oil drops start to detach from the clay. During detachment most of the oil is released but in some cases a small amount of oil residue is left behind on the clay substrate.
Our results for different salinity levels indicate that the kinetics of this wettability change correlates with a simple buoyancy over adhesion force balance and has a time constant of hours to days; i.e., it takes longer than commonly assumed.
The unexpectedly long time constant, i.e. longer than expected by diffusion alone, is compatible with an electrokinetic model. It is an important finding which provides new insights into the pore-scale mechanism of LSF and also has implications for the execution of low salinity coreflooding experiments, i.e. provides how long it takes to reach equilibrium and at which time scale a response to LSF can be expected.
Koroteev, Dmitry Anatolyevich (Schlumberger) | Dinariev, Oleg (Schlumberger) | Evseev, Nikolay (Schlumberger) | Klemin, Denis Vladimirovich (Schlumberger R&D Inc.) | Safonov, Sergey (Schlumberger) | Gurpinar, Omer M. (Schlumberger) | Berg, Steffen (Shell Global Solutions International BV) | vanKruijsdijk, Cor (Shell) | Myers, Michael (Shell) | Hathon, Lori Andrea (Shell International E&P Co.) | de Jong, Hilko (Shell Oil Co.) | Armstrong, Ryan (Shell)
Fast and reliable EOR process selection is a critical step in any EOR project. The digital rock (DR) approach jointly developed by Shell and SLB is aimed to be the smallest scale yet advanced EOR Pilot technology. In this document, we describe the application of DR technology for screening of different EOR mechanisms at pore-scale focused to enhance recovery from a particular reservoir formation. For EOR applications DR brings unique capabilities as it can fully describe different multiphase flow properties at different regimes.
The vital part of the proposed approach is the high-efficient pore-scale simulation technology called Direct Hydrodynamics (DHD) Simulator. DHD is based on a density functional approach applied for hydrodynamics of complex systems. Currently, DHD is benchmarked against multiple analytical solutions and experimental tests and optimized for high performance (HPC) computing. It can handle many physical phenomena: multiphase compositional flows with phase transitions, different types of fluid-rock and fluid-fluid interactions with different types of fluid rheology. As an input data DHD uses 3D pore texture and composition of rocks with distributed micro-scale wetting properties and pore fluid model (PVT, rheology, diffusion coefficients, and adsorption model). In a particular case, the pore geometry comes from 3D X-ray microtomographic images of a rock sample. The fluid model is created from lab data on fluid characterization. The output contains the distribution of components, velocity and pressure fields at different stages of displacement process. Several case studies are demonstrated in this work and include comparative analysis of effectiveness of applications of different chemical EOR agents performed on digitized core samples.
Increasing oil production by injection of designer water - also known as low salinity water - into a reservoir has recently attracted substantial attention from the oil producing community. The phenomenon has been studied by many researchers and low salinity water flooding is currently being applied in the field. On a macroscopic level, the effect can be parameterized as effective wettability modification to a more water-wet state but on a microscopic level, the effect is still not very well understood.
Most researchers agree that in sandstone rock, the mechanism is related to clay minerals but most of the experimental evidence is provided on the macroscopic scale (core flooding experiments) or even the field scale. Observations are not fully consistent and the predictability of the effect is limited. In a preceding publication [Petrophysics 2010, 51(5), 314-322] direct experimental evidence was provided for the detachment of oil droplets from a clay substrate upon exposure to low salinity brine.
The brine salinity for designer water flooding falls within a narrow window of opportunity: when too high, no additional oil production is observed; when too low, clay swelling and/or deflocculation may result in formation damage in the field. This raises the question whether there is a regime where oil is released with no or only minor formation damage and what the optimum salinity level for this would be. In this follow-up study, experiments are conducted on montmorillonite clay (which is a swelling clay belonging to the group of smectite clays) where the amount of released oil and the degree of formation damage are studied as a function of the salinity level. Starting at very high salinity (26,000 mg/L totally dissolved solids, TDS) no release of oil was observed and the clays remained stable. At very low salinity (2,000 mg/L TDS), up to 30% of the oil was released accompanied by substantial formation damage. There is, however, an intermediate salinity regime between 6,000 and 15,000 mg/L TDS where the formation damage is only very minor or not visible at all and still 10-30% of the initially attached oil is released. This is the regime of interest for field applications, although salinity levels have to be evaluated for the type of clay present in the formation rock.