Crude Oil/brine/rock Research Articles

Propagation of mineral dissolution waves driven by cation exchange in low salinity waterflooding

Low salinity waterflooding (LSWF) is an emerging improved/enhanced oil recovery (IOR/EOR) technique with an applicability in both sandstone and carbonate reservoirs. The underlying recovery mechanism of LSWF is still not completely understood due to the multiscale complex interactions occurring in crude oil/brine/rock (COBR) systems. There are several proposed mechanisms, where mineral dissolution is the most prominent among them. The objective of this paper is to study the brine-rock interactions, and understand the propagation of mineral dissolution waves in LSWF processes through theoretical analysis and geochemical modeling. A reactive transport geochemical modeling using PHREEQC (pH-REdox-EQuilibrium in C programing language) simulator has been carried out to understand the interplay of different geochemical effects such as multivalent cation exchange, and mineral dissolution during flow and transport in LSWF. The presence of clays and carbonate cements is most common in sandstone reservoirs, while some carbonate reservoirs also contain clay minerals. Therefore, a core scale geochemical model containing clay and carbonate minerals as active minerals for brine-rock interactions is chosen as a representative analog for most sandstone reservoirs and some of the carbonate reservoirs in this study. The results show that LSWF disturbs the geochemical equilibrium between the formation brine and reservoir rock minerals thereby causing the carbonate mineral dissolution. It is also inferred that without the cation exchange effect of clay minerals, carbonate mineral dissolution effects are local and they occur only close to the inlet of a core plug sample during LSWF. The new equilibrium between brine and rock minerals is then established rapidly. In the presence of clay minerals and cation exchange effect, the clay surfaces were found to preferentially adsorb divalent cations over monovalent cations during LSWF. Such cation exchange process softens the injected low salinity brine to maintain the brine under saturation with respect to carbonate minerals, and subsequently propagates carbonate mineral dissolution waves across the full length of the core sample. The novelty of this work is that it proposes and demonstrates a new geochemical based mechanism for LSWF, i.e., the propagation of mineral dissolution waves driven by the cation exchange process in the reservoir. The identified mechanism has several practical implications in the field: (1) carbonate mineral dissolution and the associated local pH increase can extend from local to reservoir scale, (2) the resulting mineral dissolution effectively releases the oil attached to the mineral surfaces, and (3) increasing the pH modifies the surface charges of both the rock and crude oil to be more negatively charged. The resultant electrostatic repulsion between the two interfaces would increase the water-wetness of rock surfaces to achieve higher improved oil recovery in LSWF.

Influence of Sandstone Mineralogy on the Adsorption of Polar Crude Oil Components and Its Effect on Wettability

The crude oil–brine–rock (COBR) system is a combination of contacting phases where polar organic molecules in crude oil, inorganic ions from the brine phase, and charged mineral surfaces participate in complex interactions. One of the surface phenomena that occur in the COBR system is the adsorption of polar crude oil components, which can directly affect the capillary forces and wettability of the rock. The purpose of this research work was to determine polar organic component (POC) adsorption trends for sandstones of different origins and mineralogical compositions. Adsorption preferences for acidic and basic POCs were quantified by potentiometric titration during dynamic core flooding tests using modified crude oil. The influence of POC adsorption on wettability was investigated by evaluating capillary forces during the displacement of oil in a spontaneous imbibition (SI) process. The results of this work showed a clear relationship between the intensity of POC adsorption and sandstone mineralogy. Greater adsorption capacity and a predominant affinity for bases compared to that for acids were found in the sandstone material containing a sufficient amount of reactive illite clay minerals. On the other hand, the sandstone material consisting mainly of quartz with an insignificant content of kaolinite clay did not show a pronounced tendency to adsorb POCs. All the studied rock materials have also shown a significant impact of POC adsorption on capillary forces and wettability, confirmed during SI tests. As a result, a detailed mineralogical analysis along with crude oil chemistry is required to properly evaluate sandstone wettability and competently plan core flooding laboratory studies.

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.

Modelling the effects of reservoir parameters and rock mineralogy on wettability during low salinity waterflooding in sandstone reservoirs

Low salinity waterflooding has been reported to yield incremental oil recovery from both field applications and laboratory experiments compared to regular waterflooding. Crude oil-brine-rock (COBR) interactions dictate wettability alteration during low salinity waterflooding in sandstones. In this work, triple-layer surface complexation modelling (TLM) is utilised to simulate the interactions at rock-brine and oil-brine interfaces, while accommodating the crucial role of sandstone mineralogy in surface chemistry. Derjaguin-Landau-Verwey-Overbeek (DLVO) theory is applied to characterise the COBR stability. Moreover, we propose the use of the maximum energy barrier (MEB) parameter, which is calculated from the DLVO theory's interaction potential, as an indicator of reservoir wettability.Correlating the MEB with the experimentally measured contact angles revealed an abrupt increase in contact angles as the MEB drops below the zero-value thereby leading to a less water-wet COBR system. Results analyses showed that the different clays affect the rock-brine zeta potential and wettability distinctly based on their surface site densities and specific surface areas. And the studied clays cause the zeta potential to become more negative in the order: smectite > montmorillonite > illite > chlorite > kaolinite. Subsequently, further investigation employing the developed TLM and MEB revealed that higher amounts of kaolinite will make the reservoir more oil-wet.Lastly, the sensitivity analysis performed on reservoir wettability indicated that the ionic composition is the most important factor to affect rock wettability followed by pH and temperature. Moreover, the presence of CaCl2 salt in the formation water significantly supresses the areas of strong water wettability under varying reservoir conditions compared to NaCl salt.The work conducted in this study presents a novel approach to model the individual and combined effects of sandstone minerals, specifically, quartz, kaolinite, chlorite, illite, montmorillonite and smectite, on the overall sandstone zeta potential behaviour. Furthermore, a new method was proposed to characterise reservoir wettability as a function of the maximum energy barrier which allowed us to obtain valuable insights into the most affecting reservoir parameters on COBR wettability. These findings will have practical implications to efficiently design the low salinity waterflooding processes for sandstone reservoir applications.

Investigation of crude oil properties impact on wettability alteration during low salinity water flooding using an improved geochemical model

In low-salinity water flooding (LSWF), modifying the injected brine composition leads to greater oil recovery from carbonate reservoirs. The processes that control improved recovery during LSWF are not totally clear, which could lead to ambiguities in finding optimum brine composition regarding wettability alteration (WA) toward water wetness. One of the methods to determine WA is bound product sum (BPS) calculation using geochemical tools. In the case of wettability improvement, the BPS value of a crude oil-brine-rock (COBR) system should be at its minimum value. In this study, an improved geochemical model is developed, which includes the effects of oil composition (i.e., acid number, base number, and weight percent of nonhydrocarbon components) and physical properties of oil (i.e., density, viscosity, and solution gas-oil ratio) on COBR interactions. The proposed method generates BPS as a function of temperature, pressure, oil and brine composition, and pH for carbonate rocks. The model applicability was validated using several experimental data sets available in the literature. The results of the improved BPS model were in line with the results of contact angle and zeta potential measurements as the major indices of rock wettability. BPS calculations using the available geochemical tools sometimes failed to predict the correct WA trend since they overlooked the impact of oil properties on COBR interactions. The model predictability was also compared with the results of an available geochemical tool, PHREEQC, and the results demonstrate just how important the effect of oil properties and composition inclusion on wettability determination is. The improved BPS approach could be successfully utilized as an optimization tool to optimize the water composition during LSWF for a given COBR system.

Impact of polymer on electro-kinetic properties of crude oil, brine and rock interfaces

In recent years, there has been a growing interest in the petroleum industry to improve the ultimate oil recovery method by using low-salinity polymer flooding (LSPF) with the synergistic effect by combining polymer and low-salinity water injection. Although numerous research studies have focused on the technical and economic benefits of low salinity polymer (LSP), to the best of our knowledge, crude oil/brine/rock (COBR) interactions in LSP did not receive enough attention due to the complexity of the interactions between brine, polymer, crude oil, and the rock surface. Therefore, this study aimed to investigate the impact of polymer on COBR interactions with different brine chemistry and improve the understanding of active mechanisms of LSPF. Partially hydrolyzed polyacrylamide (HPAM) polymer, Boise rock, a crude oil sample from an Omani oil field, and several brine solutions were used in the study. Zeta potential and pH measurements were performed to examine the role of polymer on electrical properties of brine/rock and oil/brine interfaces. In addition, rheological properties of the polymer were investigated at different salinity and brine compositions. Changes in Boise rock surface charge through zeta potential measurements were investigated in the absence and presence of polymer. pH and rheology measurements for equilibrated brines with and without polymer and zeta potential of crude oil/equilibrated brine were performed. The results revealed that the addition of polymer to the brine not only increased the viscosity, but also affected the electrical charge at crude oil/brine/rock (COBR) interfaces and triggered pH increase of the brine. The impact of polymer on COBR interactions is mainly controlled by the water chemistry. In the absence of ions, polymer molecules did not affect the charge of COBR interfaces, while in the presence of ions, at different compositions and concentrations, the charge of COBR interfaces changed to become more negative. Thus, the presence of polymer in brine increases the electrostatic repulsion between crude oil/brine and brine/rock interfaces, increases electrical double layer (EDL) thickness, and makes the water film more stable. A direct relationship between the viscosity and zeta potential of the polymer solutions was observed at different brine chemistry. Moreover, the presence of polymer at different brine chemistry resulted in an increase in pH of the aqueous phase. This could in turn reduce the adsorption of polar organic acids from crude oil. Therefore, in addition to the reduction of the water-oil mobility ratio, polymer molecules could contribute to an increase in the repulsion forces between COBR interfaces and an increase in the pH of the aqueous solution.

Ionic Interactions at the Crude Oil-Brine-Rock Interfaces Using Different Surface Complexation Models and DLVO Theory: Application to Carbonate Wettability.

The impact of ionic association with the carbonate surface and its influence toward carbonate wettability remains unclear and is an important topic of interest in the current literature. In this work, a triple layer model (TLM) approach was used to capture the electrokinetic interactions at both calcite–brine and oil–brine interfaces. The developed TLM was assembled against measured ζ-potential values from the literature, successfully capturing the trends and closely matching the ζ-potential magnitudes. The developed TLM was compared to a diffused layer model (DLM) presented in previous works, with the DLM showing a better match to the ζ-potential values for seawater brine solutions. The ζ-potential values predicted from both surface complexation models (SCMs) were used to calculate the total interaction energy (or potential) based on the Derjaguin, Landau, Verwey, and Overbeek (DLVO) theory. It was observed that low Mg2+ and high SO42– concentrations in modified composition brine (MCB) made the calcite–brine interface more negative. However, at the oil–brine interface, low Mg2+ made the oil–brine interface more negative but high SO42– concentrations slightly shifted the oil–brine ζ-potential toward negative. At the crude oil–brine–rock (COBR) interfaces, low Mg2+ and high SO42– concentrations in the MCB were observed to generate a greater repulsive interaction energy, which could trigger carbonate wettability alteration toward water wetness. The absolute sum of the ζ-potential at both interfaces was observed to be correlated to the total interaction potential at a 0.25 nm separating distance. Thus, an increase in the absolute sum of the ζ-potentials would generate a greater repulsive interaction potential and trigger wettability alteration. Therefore, these SCMs can be applied to design modified composition brine capable of triggering a repulsive interaction energy to alter carbonate wettability toward water wetness.

Predicting the electrokinetic properties on an outcrop and reservoir composite carbonate surfaces in modified salinity brines using extended surface complexation models

Surface complexation models (SCM), based mainly on the diffuse double layer (DDL) theory, have been used to predict zeta potential at the crude oil-brine-rock (COBR) interface with limited success. However, DDL is inherently limited in accurately predicting zeta potential by the assumptions that all the brine ions interact with the rock surface at the same plane and by the double layer collapse at higher brine ionic strength (>1M). In this work, a TLM-based SCM captured zeta potential trends at the calcite-brine interface with ionic strength up to 3 M. An extended DDL and TLM-based SCMs were used to predict the electrokinetic properties of a composite carbonate rock showing a different mineralogical composition. The extended TLM-based SCM captured the zeta potential prediction trends and magnitude, highlighting the contribution of the inorganic minerals and organic impurities on the composite carbonate surface. In contrast, the extended DDL-based SCM captured the zeta potential trends but failed to capture the magnitude of the measured zeta potential. Interestingly, the TLM-based SCM predicted a positive SP for the rock-brine interface, which could explain the oil-wet nature of composite carbonate rocks due to electrostatic adsorption of negatively charged carboxylic acids. Conversely, the DDL-based SCM predicted a negative SP, leading to an inaccurate interpretation of the electrokinetic properties at the rock-brine interface. Thus, the use of extended TLM-based SCM was required to accurately predict the zeta potential and account for the adsorption of carboxylic acids on the reservoir composite carbonate surface.

Crude Oil–Brine–Rock Interactions in Tight Chalk Reservoirs: An Experimental Study

We present a systematic study of crude oil–brine–rock interactions in tight chalk cores at reservoir conditions. Flooding experiments are performed on outcrops (Stevns Klint) as well as on reservoir core plugs from Dan field, the Ekofisk and Tor formations. These studies are carried out in core plugs with reduced pore volumes, i.e., short core samples and aged with a dynamic ageing method. The method was evaluated by three different oil compositions. A series of synthetic multicomponent brines and designed fluid injection scenarios are investigated; injection flow rates are optimized to ensure that a capillary-dominant regime is maintained. Changes in brine compositions and fluid distribution in the core plugs are characterized using ion chromatography and X-ray computed tomography, respectively. First, we show that polar components in the oil phase play a major role in wettability alteration during ageing; this controls the oil production behavior. We also show that, compared to seawater, both formation water and ten-times-diluted seawater are better candidates for enhanced oil recovery in the Dan field. Finally, we show that the modified flow zone indicator, a measure of rock quality, is likely the main variable responsible for the higher oil recoveries observed in Tor core samples.

Adsorption of Crude Oil Components onto Carbonate and Sandstone Outcrop Rocks and Its Effect on Wettability

The processes of establishing and altering reservoir wettability are still subjects of discussion due to the complexity of the underlying crude oil–brine–rock interactions. This study was aimed at ...

Pore scale visualization of fluid-fluid and rock-fluid interactions during low-salinity waterflooding in carbonate and sandstone representing micromodels

Low Salinity Waterflooding (LSWF) has become a popular tertiary injection EOR method recently. Both fluid-fluid and fluid-rock interactions are suggested as the contributing mechanisms on the effectiveness of LSWF. Considering the contradictory remarks in the literature, the dominating mechanisms and necessary conditions for Low Salinity Effect (LSE) varies for different crude oil-brine-rock (CBR) systems. The aim of the present study is to investigate LSE for an oil field in the Middle East that is composed of separate sandstone and limestone layers. Contact angles and Interfacial Tension (IFT) are measured to have more insight on the CBR under investigation. Visual experiments were conducted in micromodels to determine the dominating mechanisms of LSE. Experiments were conducted under water-wet and oil-wet conditions for both sandstone and limestone representing micromodels. Several secondary and tertiary injection scenarios were performed with different levels of salinities. Consecutive injection of high-salinity and low-salinity water illustrated that LSE occurs under certain conditions. For both rock types, during the secondary high salinity injection, the oil trapping mechanism was mostly snap-off under water-wet condition, while fingering/bypassing was dominant under oil-wet conditions. LSWF causes diminutive changes of saturation redistribution in water-wet micromodels. Even in rare occasions that oil ganglia started to reshape or redistribute, it became trapped again in the downstream pores of the model, and not produced effectively. Contrary to this, LSWF was very effective under oil-wetting conditions. Continuous oil films, which exist in oil-wet condition, are beneficial for the effectiveness of LSE. Measured IFT and contact angles cannot justify the observed LSE. Additionally in the designed micromodels, any contribution of clay or fine migration to the LSE is ruled out. Spontaneous formation of the micro-emulsion was a very weak mechanism in our experiments and did not contribute to pushing oil out of the dead end pores or divert the flow path to the un-swept areas. Visual investigations suggested that formation of the visco-elastic interface can be the dominating mechanism for LSE in the investigated CBRs which is more effective in the case of oil-wet system due to the lack of snap-off trapping mechanism.

An experimental investigation of smart-water wettability alteration in carbonate rocks – oil recovery and temperature effects

ABSTRACT The smart water flooding has found tremendous applications in the oil recovery sector. This technique is designed by changing the concentrations of cations – mainly SO4 2-, Ca2+, and Mg2+ – in the synthetic water mixtures being injected. The complexity of the underlying reaction mechanism, compared to the sandstone counterparts, calls for substantial research in this field. The present article lists an experimental investigation of wettability alteration in carbonate rocks by focusing on the role of individual ions for the fluid-solid interactions. The oil recovery results are reported for five synthetic smart waters, as well as the real formation water in the temperature range between 25 and 70 Celsius. A chemical-based mechanism is proposed – supported by zeta-potential data – to render the role of ions in the wettability alteration process. The smart-water samples are designed to hold the same level of total dissolved solids as the seawater of the Persian Gulf. The increase in the concentration of SO4 2- ion is found to accelerate the rate of reaction in the crude oil-brine-rock (CBR) system, resulting in more wettability alteration. In addition, the Mg2+ ion is rendered more effective in the wettability change process than the Ca2+ ion. The seawater enriched with sulfate ions (two/four-fold) has yielded the highest recovery, with essential increase in higher temperatures. The elevation of temperature to 70°C has yielded an impressive outcome on the recovery – approximately 17.20% – for the best smart-water samples evaluated.

Low salinity effects on oil recovery performance: underlying physical mechanisms and practical assessment

This paper is a tentative synthesis of the main knowledge and experience gained from recent studies and application of Low Salinity Water Injection (LSWI) in carbonate and clayey silico-clastic rocks. A physical model based on ionic force is presented to explain the so-called Dual Layer Expansion (DLE) mechanism often invoked to account for the Low Salinity Effects (LSE) on rock wettability and oil recovery. The role played by the Multi Ion Exchange (MIE) mechanism is clarified, at least for clayey rocks. Eventually, the proposed physical analysis shows the complementary roles that injected brine concentration and composition can play on waterflood recovery efficiency depending on the Crude Oil Brine Rock (COBR) system under consideration. To account for the diversity of COBR systems, a straightforward modelling methodology is then proposed to simulate laboratory LSWI tests on a case-by-case basis and infer the actual evolution of residual oil saturation with brine concentration and/or composition. The simulation involves a wettability driver that may be either the global salinity or the square root of ionic force. The analysis of published results actually shows that the latter predicts low salinity effects on residual oil saturation better than the former. Hopefully, this paper contributes to the understanding of the DLE and MIE mechanisms induced by a smart water injection and provides a simple and robust methodology to simulate the reference coreflood experiments that remain necessary to assess and optimize LSWI.

Optimisation of Smart Water to Enhance Oil Recovery Efficiency in a Part of Oil Field of Upper Assam Basin, India

Researchers have proved the significance of water injection by tuning its composition and salinity into the reservoir during smart water flooding. Once the smart water invades through the pore spaces, it destabilises crude oil-brine-rock (COBR) that leads to change in wettability of the reservoir rocks. During hydrocarbon accumulation and migration, polar organic compounds were being adsorbed on the rock surface making the reservoir oil/mixed wet in nature. Upon invasion of smart water, due to detachment of polar compounds from the rock surfaces, the wettability changes from oil/mixed wet to water wet thus enhances the oil recovery efficiency. The objective of this paper is to find optimum salinity and ionic composition of the synthetic brines at which maximum oil recovery would be observed. Three core flood studies have been conducted in the laboratory to investigate the effect of pH, composition and salinity of the injected brine over oil recovery. Every time, flooding has been conducted at reservoir formation brine salinity i.e at 1400 ppm followed by different salinities. Here, tertiary mode of flooding has been carried out for two core samples while secondary flooding for one. Results showed maximum oil recovery by 40.12% of original oil in place (OOIP) at 1050ppm brine salinity at secondary mode of flooding. So, optimized smart water has been proposed with 03 major salts, KCl, MgCl2 and CaCl2 in secondary mode of flooding that showed maximum oil recovery in terms of original oil in place.

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.

Investigating the Effect of the Temperature and Pressure on Wettability in Crude Oil–Brine–Rock Systems

Wettability is a key parameter that affects the petrophysical properties of reservoir formations. The objective of the present work is to investigate the influence of the temperature and pressure o...

Wettability Alteration of Mineral Surface during Low-Salinity Water Flooding: Role of Salt Type, Pure Alkanes, and Model Oils Containing Polar Components

Low-salinity water injection is an emerging enhanced oil recovery technique and an area of active research. According to many researchers, the role of brine salinity has been attributed to its ability to change the reservoir rock wettability. The influence of different parameters such as total dissolved solids, concentration of individual ions, oil composition, lithology, acid and base number, etc., has been tested previously using different combinations of crude oil and reservoir core samples. However, because of the complex nature of crude oil–brine–rock system, there is no clear idea of the mechanism of wettability alteration and the influence of above parameters on this process. In this work, we have investigated the governing factors affecting the wettability of mineral surface using pure alkane liquids and model oils (containing organic acid and base). The wettability studies were performed through contact angle measurements over a wide range of concentration (1 mM to 1M) of monovalent and divalent ...

Bulk and Surface Aqueous Speciation of Calcite: Implications for Low-Salinity Waterflooding of Carbonate Reservoirs

Summary Low-salinity waterflooding (LSW) is ineffective when reservoir rock is strongly water-wet or when crude oil is not asphaltenic. Success of LSW relies heavily on the ability of injected brine to alter surface chemistry of reservoir crude-oil brine/rock (COBR) interfaces. Implementation of LSW in carbonate reservoirs is especially challenging because of high reservoir-brine salinity and, more importantly, because of high reactivity of the rock minerals. Both features complicate understanding of the COBR surface chemistries pertinent to successful LSW. Here, we tackle the complex physicochemical processes in chemically active carbonates flooded with diluted brine that is saturated with atmospheric carbon dioxide (CO2) and possibly supplemented with additional ionic species, such as sulfates or phosphates. When waterflooding carbonate reservoirs, rock equilibrates with the injected brine over short distances. Injected-brine ion speciation is shifted substantially in the presence of reactive carbonate rock. Our new calculations demonstrate that rock-equilibrated aqueous pH is slightly alkaline quite independent of injected-brine pH. We establish, for the first time, that CO2 content of a carbonate reservoir, originating from CO2-rich crude oil and gas, plays a dominant role in setting aqueous pH and rock-surface speciation. A simple ion-complexing model predicts the calcite-surface charge as a function of composition of reservoir brine. The surface charge of calcite may be positive or negative, depending on speciation of reservoir brine in contact with the calcite. There is no single point of zero charge; all dissolved aqueous species are charge determining. Rock-equilibrated aqueous composition controls the calcite-surface ion-exchange behavior, not the injected-brine composition. At high ionic strength, the electrical double layer collapses and is no longer diffuse. All surface charges are located directly in the inner and outer Helmholtz planes. Our evaluation of calcite bulk and surface equilibria draws several important inferences about the proposed LSW oil-recovery mechanisms. Diffuse double-layer expansion (DLE) is impossible for brine ionic strength greater than 0.1 molar. Because of rapid rock/brine equilibration, the dissolution mechanism for releasing adhered oil is eliminated. Also, fines mobilization and concomitant oil release cannot occur because there are few loose fines and clays in a majority of carbonates. LSW cannot be a low-interfacial-tension alkaline flood because carbonate dissolution exhausts all injected base near the wellbore and lowers pH to that set by the rock and by formation CO2. In spite of diffuse double-layer collapse in carbonate reservoirs, surface ion-exchange oil release remains feasible, but unproved.

Atomic Force Spectroscopy Using Colloidal Tips Functionalized with Dried Crude Oil: A Versatile Tool to Investigate Oil–Mineral Interactions

The recovery efficiency of water flooding (water injection in oil reservoirs to recover oil) can be improved by modification of the ionic composition of the brine. This effect is attributed to changes in the physicochemical interactions within in the crude oil–brine–rock (COBR) system. To systematically modify these interactions, gain predictive capability, and optimize recovery efficiency, further understanding of these systems is required. Our work introduces a new tool to facilitate the study of interactions in such ternary systems. Utilizing atomic force spectroscopy, we developed a custom dried oil-coated probe which directly measures the interactions between crude oil and a mineral substrate in a varying aqueous environment at their natural length scale. In most of the previous studies, COBR interactions were studied by using model systems wherein crude oil was represented by organic acids, for instance, which is a significant simplification of natural systems that may be unwarranted. In this study, we measured the interaction forces between mineral surfaces and actual crude oils. The experiments allow us to systematically test the effect of brine composition on the forces between mineral surfaces and crude oil components in all their complexity under realistic reservoir conditions. Our results illustrate the reproducibility of measurements made using this custom tool by using multiple probes to show salinity-dependent repulsive interactions between the oil coating and a mica substrate. These electrostatic interactions are consistent with trends expected by the Debye–Hückel theory, showing a decrease in repulsive forces as a function of increasing monovalent ion concentration. Adherence to this expected trend provides insight into the COBR interactions in a particular oil reservoir with particular oil, brine, and mineral compositions. Additionally, the presence of electrostatic forces suggests that the dried crude oil coating retains surface charge throughout the drying procedure. Therefore, this tool has the potential to represent or approximate the electrostatic interactions of the original liquid crude oil system during the study of COBR interactions.

Effect of multi-component ions exchange on low salinity EOR: Coupled geochemical simulation study

Abstract The mechanism(s) of Low salinity water flooding (LSWF) has been extensively investigated for 15–20 years, as a cost-effective and environmentally friendly technique for improved oil recovery. However, there is still no consensus on the dominant mechanism(s) behind low salinity effect due to the complexity of interactions in the Crude oil/Brine/Rock (COBR) system. While wettability is most agreed mechanism of low salinity EOR effect. Nevertheless, the mechanism(s) behind the wettability change is debated between multi-component ion exchange (MIE) and double layer expansion (DLE) in sandstone reservoirs. This paper aims to investigate the effectiveness of MIE with a coupled geochemical-reservoir model using published experimental data reported by Nasralla and Nasr-El-Din [1]. We created core-scale numerical models with parameters identical to those used in the experiments. We simulated the low salinity effect using a commercial reservoir simulator, CMG-GEM, by coupling three chemical reactions: (1) aqueous reaction, (2) multi-component ion exchange, and (3) mineral dissolution and precipitation. We modelled the adsorption of divalent cations on the surface of the clay minerals during low salinity water injection. Simulation results were compared with the experimental results. Simulation results show that the fractional adsorption of divalent cations (Ca 2+ ) increased almost 25% by injecting a 2000 ppm NaCl solution, compared to initial 10,000 ppm NaCl. Injecting a 2000 ppm of CaCl 2 solution, however, significantly increased the adsorbed Ca 2+ from 0.1 to 1, which implies the complete saturation of mineral surface with divalent cations. Moreover, injecting 50,000 ppm of CaCl 2 solution also demonstrated the same effect as the 2000 ppm CaCl 2 solution but with a faster rate. Upon combining the simulation and experimental results, we concluded that the multi-component ion exchange is not the sole mechanism behind low salinity effect for two reasons. First, almost 10% additional oil recovery was observed from the experiments by injecting the 2000 ppm CaCl 2 compared with 50,000 ppm CaCl 2 solutions. Even though in both cases the surface is expected to be fully saturated with Ca 2+ according to the geochemical modelling. Second, 6% incremental oil recovery was achieved from the experiments by injecting 2000 ppm NaCl solution compared with that of 50,000 ppm NaCl. Although 25% incremental adsorption of divalent cations (Ca 2+ ) were presented during the flooding of the 2000 ppm NaCl solution. Therefore, it is worth noting that the electrical double layer expansion due to the ion exchange needs to be taken into account to pinpoint the mechanism(s) of low-salinity water effect.