Controlled Salinity Waterflooding Research Articles

Controlled salinity water flooding and zeta potential: Insight into a novel enhanced oil recovery mechanism

Controlled salinity water flooding also known as engineered water flood has been tested as a potential enhanced oil recovery (EOR) method in laboratory as well as at pilot/field scale. However, there are cases seen where the method has failed to show its potential for EOR. Scientists believe that the lack of understanding of case specific underlying mechanism is the primary reason. Many of the literatures claims reduction of interfacial tension as the primary oil recovery mechanism; but recent findings highlighted that modification of electrical charges on rock surface with response to injection brine salinity has greater effect. In order to investigate the same and in search of more insightful mechanism, in this study we have designed and performed experiments with selected chemicals which can modify surface properties of sandstone and also the oil water interfacial tension. The electrical charge of the rock surface and oil–brine​ interfacial tension were modified by tuning salinity of injection water and adding surfactants (sodium dodecyl benzene sulfonate, SDBS and cetyltrimethylammonium bromide, CTAB). The electrical charge of the sandstone surfaces was quantified with zeta potential measurement. The oil recovery potential of the injection fluids was tested through laboratory core flooding experiments at controlled near reservoir conditions. Superposition of all the obtained results revealed that low salinity injection brine modifies the sandstone surface to higher negatively charged state than high salinity water. Therefore, with a negatively charged oil–brine interface it causes strong repulsive forces promoting detachment of residual oil and subsequent mobilization. The hypothesis is also proved by the fact that SDBS in spite of resulting in a lower interfacial tension reduction than CTAB yielded higher oil recovery. This is because of the negative zeta potential caused by SDBS to sandstone surface in comparison to the positive zeta potential observed in the case of CTAB.

Relevance of zeta potential as a tool for predicting the response of controlled salinity waterflooding in oil–water-carbonate systems

Zeta potential has been proposed as a key parameter for predicting the response of controlled salinity waterflooding, as correlation with additional oil recovery has previously been established. However, it is unclear if there is a causal effect and if this parameter can be used as a unique predictive tool. We provide new insights with a detailed investigation into the role of the change of polarities of oil/water/rock interfaces on the additional oil recovery. Core flooding experiments with streaming potential and electrophoretic mobility measurements were performed to obtain insights into the electrostatic interactions that occur during oil recovery on Estaillades rock. Two different injection scenarios were followed in one crude oil/brine/rock (COBR) system: one conventional injection with decreasing salinity and one inverse injection with increasing salinity.Results indicated that oil recovery in secondary mode was more important using formation brine compared to low salinity brine. Also, almost no additional oil recovery was observed in tertiary mode irrespective of the injection scenario. Rock/water zeta potential was found positive in formation brine, and negative in the low salinity brines. The determination of oil/water polarity was more difficult as many inconsistencies between streaming potential and electrophoretic mobility measurements were observed. We propose several explanations for these discrepancies, including that the difference in zeta potential at fully water saturation and at residual saturation is not necessarily dependent on oil polarity as it can be induced by a change in rock exposed surface and in the distribution in water flow paths during measurements. The overall results suggest that zeta potential cannot be used as a unique indicator to predict the low salinity response of a COBR system.

A calibrated surface complexation model for carbonate-oil-brine interactions coupled with reservoir simulation - Application to controlled salinity water flooding

Vast majority of past studies that have been conducted on controlled salinity water flooding (CSWF) use diffuse layer model (DLM) that calculates only the surface potential, which can be significantly different from the ζ-potential of the interface. Importantly, stability of the water-film (between the oil and the rock surface) which dictates ultimate oil recovery is related to ζ-potential. As such, using DLM calculated surface potential (directly) for CSWF can be misleading. Additionally, most of the existing DLMs use integer charges instead of fractional charges to model carbonate-brine interactions, which may not represent the actual carbonate crystallographic. We present a triple layer surface complexation model (TLM) which offers the option to locate and distribute charge of the adsorbing ion(s) at three locations. TLM can therefore calculate potentials at three different locations within the Stern layer. To the best of our knowledge, only few authors have used TLM to simulate CSWF. However, some surface reactions were ignored in these models. For instance, adsorption of monovalent ions such as Na + and Cl − ions was ignored in some of the few available TLMs. Also, the effect of basic-oil components was not considered in some TLMs, and lastly, some TLMs used integer charges for the carbonate surface group. This study introduced a comprehensive TLM that includes all these complexities. Moreover, we introduced a new wettability indicator (WI) that is related to the electrostatic forces between the oil-brine and the rock-brine interfaces. That is, WI was calculated from ζ-potentials at the oil-brine and rock-brine interfaces. The TLM, built in a geochemical simulator, PHREEQC, was then coupled with UTCHEM, a multiphase reservoir simulator. The developed simulator based on the TLM-CSWF model was tested against several experimentally measured oil recovery data sets. Results of the model suggest that Oil basic component significantly impacts oil-brine interface ζ-potential irrespective of temperature, brine composition, and ionic strength. On the otherhand, Na + ions in brine may influence oil-brine ζ-potential, and this relates to temperature, brine composition, and ionic strength. The results further suggest that injection of (sulfate-free) diluted brine in chalk resulted to increased oil adhesion, shifting the reservoir to oil-wet condition. Hence, no additional oil is recovered with this brine injected at tertiary oil recovery stage. Finally, the results showed that wettability is related to ζ-potentials at the oil-brine and rock-brine interfaces, and the carbonate rock would be strongly oil-wet or water-wet only at significantly large magnitude of ζ-potentials at the interfaces. • A new triple-layer surface complexation model developed to characterize carbonate-brine-oil interactions. • The model is tested against several experimentally measured zeta potential and oil recovery data sets. • The model suggests that SO 4 −2 ion adsorption tends to decrease CO 3 −2 adsorption at the rock surface and vice-versa. • The model showed that only a small fraction of the carbonate-oil-brine reactive sites are involved in the geochemical reactions.

Relationship Between Zeta Potential and Wettability in Porous Media: Insights From a Simple Bundle of Capillary Tubes Model

Hypothesis & MotivationExperimental data suggest a relationship between the macroscopic zeta potential measured on intact rock samples and the sample wettability. However, there is no pore-scale model to quantify this relationship. MethodsWe consider the simplest representation of a rock pore space: a bundle of capillary tubes of varying size. Equations describing mass and charge transfer through a single capillary are derived and the macroscopic zeta potential and wettability determined by integrating over capillaries. Model predictions are tested against measured data yielding a good match. FindingsMixed- and oil-wet models return a macro-scale zeta potential that is a combination of the micro-scale zeta potential of mineral-brine and oil-brine interfaces and the relationship between macro-scale zeta potential and water saturation exhibits hysteresis. The model predicts a similar relationship between zeta potential and wettability to that observed in experimental data but does not provide a perfect match. Fitting the model to experimental data allows the oil-brine zeta potential to be estimated at conditions where it cannot be measured directly. Results suggest that positive values of the oil-brine zeta potential may be more common than previously thought with implications for surface complexation models and the design of controlled salinity waterflooding of oil reservoirs.

Role of the calcite-water interface in wettability alteration during low salinity waterflooding

Wettability alteration has been widely accepted as the key process for enhanced oil recovery during controlled salinity waterflooding. However, the decisive mechanism causing wettability alteration, particularly for crude-oil-brine-carbonate-rock systems, is not fully understood. Zeta potential is a key electrochemical parameter for the mineral-brine interface and is sensitive to physicochemical changes at the interface. In this study, we conducted core-flooding tests integrated with zeta potential measurements to characterize changes in wettability, oil recovery and zeta potential on two carbonate rock samples, Carbonate-I and Carbonate-II, comprised of close to pure calcite. Following the same coreflooding protocol with the same crude oil and flooding brine compositions, the two samples showed different behaviour. Incremental oil recovery during controlled (low) salinity waterflooding was observed in the oil-brine-Carbonate-II system (8% incremental oil recovery) but there was no response for the Carbonate-I system. The zeta potential of the Carbonate-I and Carbonate-II samples also showed different behaviour in high salinity formation brine, with Carbonate-I returning a positive zeta potential, consistent with previous published measurements, but Carbonate-II returning an anomalously negative value. We suggest that the different zeta potential and EOR behaviour is most likely caused by the different proportions of crystal faces and edges in each sample that are exposed to brine. The low permeability Carbonate-II sample contains nanoscale pores and the edges of the calcite crystals are the dominant surface in contact with brine. Our results suggest that textural variations in natural carbonates control calcite-brine interfacial properties and the behaviour during controlled salinity waterflooding.

Zeta potential in intact carbonates at reservoir conditions and its impact on oil recovery during controlled salinity waterflooding

It is well known that oil recovery from carbonate reservoirs can be increased by modifying the injected brine composition in a process ‘controlled salinity water-flooding’ (CSW). However, the mineral- to pore- scale processes responsible for improved oil recovery (IOR) during CSW remain ambiguous and there is no method to predict the optimum CSW composition for a given crude-oil-brine rock system. Here we report the first integrated experimental measurements of zeta potential and IOR during CSW obtained at reservoir conditions. The zeta potential is a measure of the electrical potential at mineral-brine and oil-brine interfaces and controls the electrostatic forces acting between these interfaces.We find that the measured zeta potential in clean samples saturated with formation brine is typically positive and becomes more negative with brine dilution irrespective of temperature. After aging and wettability alteration, the zeta potential changes and we suggest a more positive zeta potential indicates a positive zeta potential at the oil-brine interface and vice-versa. Injecting low salinity brine yields IOR when the oil-brine zeta potential is identified to be negative, but no response when it is identified to be positive, consistent with the hypothesis that IOR during CSW is caused by an increase in the repulsive electrostatic force acting between mineral-brine and oil-brine interfaces. We suggest that the optimum brine composition for IOR during CSW should be chosen to yield the largest change in zeta potential at the mineral-brine interface with opposing polarity to the oil-brine interface and can be determined using the experimental method reported here.

A salinity cut-off method to control numerical dispersion in low-salinity waterflooding simulation

Low-salinity or controlled salinity waterflooding (LSWF) is a promising enhanced oil recovery (EOR) technique. In simulations of this process, numerical dispersion smears saturation fronts, causing errors in the results. The objective of this work is to control these effects in LSWF simulation. We examine the impact of numerical dispersion on simulated LSWF performance. The low-salinity (LS) front is smeared even at unfeasibly fine grids. The velocities of the water fronts are altered. A numerical mixed zone forms around the interface between the injected and resident brines. This mimics a typical physical mixing effect.In reservoir simulation, threshold salinities are defined where the low salinity effect (LSE) is first encountered. It has been suggested that numerical dispersion effects can be corrected by imposing effective thresholds. We demonstrate that existing methods to evaluate these effective salinities do not accurately predict the salt front movement especially when dispersion is significant.We propose a simple simulation-based approach to evaluate the effective salinities based on the conservation of volumes of the resident and injected brines in the reference and upscaled solutions. After comparing analytical and corrected coarse-grid solutions in one-dimension, the effectiveness of the approach is demonstrated in multi-dimensional systems.A method is proposed to control the numerical mixed zone to replicate a physical longitudinal mixing effect. This method is demonstrated in one-dimension and does not require a fine-grid numerical solution as a benchmark. We investigate the effects of effective thresholds on the modeled transverse mixing or dispersion. A method to model transverse dispersion in simulations with an effective longitudinal component is suggested. This method is extended to the explicit modeling of physical dispersion in systems with transverse flows.We can now simply evaluate the effective salinities for a simulation grid; and control its numerical dispersion effects to representative physical mixing or dispersion.

Direct insights into the pore-scale mechanism of low-salinity waterflooding in carbonates using a novel calcite microfluidic chip

One of the key open questions in the area of low or controlled salinity water flooding (LSWF or CSWF) is how the observed oil recovery at macro-scale (e.g. Darcy or core-scale) can the explained and what underlying microscopic mechanisms drive it. Thus far, the micromodel investigation of LSWF has been limited to sandstones, remaining challenging to apply to carbonates. In this paper we aim to i) extend the capability to fabricate a novel calcite micromodel using Iceland spar calcite crystal, ii) investigate the pore-scale mechanisms leading to oil recovery from carbonates.A target crude oil-brine-rock (COBR) system was first selected. To screen potential brines which can produce low-salinity-effect (LSE) and to guide the design of the micromodel experiments, contact angle measurements were carried out using two methods: i) contact angle under fixed, and ii) under dynamic salinity condition. The micromodel displacement experiments were then performed by flooding an oil saturated model with high salinity water followed by low salinity water injection to displace the high salinity water and observe any potential changes to the configuration and saturation of the residual oil. Additionally, the effect of connate water presence on the efficiency of LSE was investigated. To account for the time effects of the low salinity process, the experiments were monitored for an extended time period in order of several days to a month.For the COBR system studied in the micromodel, the results clearly show that when brine salinity is lowered the microscopic sweep efficiency is improved; providing a direct in-situ evidence for wettability alteration to a more water-wetting state. The presence of connate water enhanced the efficiency of LSWF both in terms of speed (time-scale) and quantity of oil recovery. It is postulated that in the presence of connate water an initial water-film around the calcite surface is present which facilitates the diffusive transport of brine ions when low salinity is injected. Thus it is favorable to have an initial water film present; a case for mixed-wettability. We observed that the oil production was non-instantaneous characterized by a prolonged induction time and a slow “layer-by-layer” recovery either from the pore body or throat wall; a process we refer to as “peel-off”. Before the oil can be removed from the calcite surface, de-wetting (or de-pinning) patterns were formed which grew and coalesced toward formation of a clearly visible larger pattern. Ultimately, the remaining oil under low salinity was comparatively much less compared to the end of high salinity step.The observed mechanism of the oil recovery and the slow associated time have direct implications for the pore-scale simulation of the process and upscaling to Darcy-scale, and the design of laboratory experiments to avoid false negative results. They would also likely imply lack of a clear oil-bank observation at core scale.

A Synergy between Controlled Salinity Brine and Biosurfactant Flooding for Improved Oil Recovery: An Experimental Investigation Based on Zeta Potential and Interfacial Tension Measurements

In this study, we have investigated the effects of brine and biosurfactant compositions on crude-oil-rock-brine interactions, interfacial tension, zeta potential, and oil recovery. The results of this study show that reduced brine salinity does not cause significant change in IFT. However, addition of biosurfactants to both high and low salinity brines resulted in IFT reduction. Also, experimental results suggest that the zeta potential of high salinity formation brine-rock interface is positive, but oil-brine interface was found to be negatively charged for all solutions used in the study. When controlled salinity brine (CSB) with low salinity and CSB with biosurfactants were injected, both the oil-brine and rock-brine interfaces become negatively charged resulting in increased water-wetness and, hence, improved oil recovery. Addition of biosurfactants to CSB further increased electric double layer expansion which invariably resulted in increased electrostatic repulsion between rock-brine and oil-brine interfaces, but the corresponding incremental oil recovery was small compared with injection of low salinity brine alone. Moreover, we found that the effective zeta potential of crude oil-brine-rock systems is correlated with IFT. The results of this study are relevant to enhanced oil recovery in which controlled salinity waterflooding can be combined with injection of biosurfactants to improve oil recovery.

Zeta potential in oil-water-carbonate systems and its impact on oil recovery during controlled salinity water-flooding.

Laboratory experiments and field trials have shown that oil recovery from carbonate reservoirs can be increased by modifying the brine composition injected during recovery in a process termed controlled salinity water-flooding (CSW). However, CSW remains poorly understood and there is no method to predict the optimum CSW composition. This work demonstrates for the first time that improved oil recovery (IOR) during CSW is strongly correlated to changes in zeta potential at both the mineral-water and oil-water interfaces. We report experiments in which IOR during CSW occurs only when the change in brine composition induces a repulsive electrostatic force between the oil-brine and mineral-brine interfaces. The polarity of the zeta potential at both interfaces must be determined when designing the optimum CSW composition. A new experimental method is presented that allows this. Results also show for the first time that the zeta potential at the oil-water interface may be positive at conditions relevant to carbonate reservoirs. A key challenge for any model of CSW is to explain why IOR is not always observed. Here we suggest that failures using the conventional (dilution) approach to CSW may have been caused by a positively charged oil-water interface that had not been identified.