Oil Recovery In Carbonates Research Articles

A Comprehensive Simulation Study of Physicochemical and Geochemical Interactions on Immiscible CO2-LSWAG Injection in Carbonates

Low-salinity water-alternating-CO2 (CO2-LSWAG) injection has been widely studied and employed due to its capability to promote enhanced oil recovery (EOR). However, there is no consensus on the dominant mechanisms for oil recovery in carbonates due to the extreme complexity of the oil–brine–rock interactions. This work proposes a comparative investigation of the physicochemical and geochemical effects of continuous CO2 and CO2-LSWAG immiscible injections on oil recovery in a carbonate core. Simulations were carried out using oil PVT properties and relative permeability experimental data from the literature. A comparison of SO42− and Mg2+ as interpolant ions, oil, water and gas production, pressure, and rock and fluid properties along the core and in the effluent was made. The results show a high recovery factor for CO2 (62%) and CO2-LSWAG (85%), even in immiscible conditions. The mineral dissolution and porosity variations were more pronounced for CO2-LSWAG than CO2. The simulation results showed that Mg2+ as an interpolant improves oil recovery more than SO42− because Mg2+ concentration in the aqueous phase after LSW injection leads to relative permeability values, which are more favorable.

Synergistic SmartWater based surfactant polymer flooding for enhanced oil recovery in carbonates

SmartWater flooding has been recognized as an efficient and practical technology to synergize with different enhanced oil recovery methods for increasing oil recovery. This article aims to investigate the beneficial synergy effect between the SmartWater and surfactant-polymer (SP) flooding for carbonate reservoirs. Both zeta potential and contact angle measurements revealed that a favorable wettability alteration was induced with SmartWater. Coreflooding experiments were performed using preserved carbonate core samples at reservoir conditions. Results demonstrated that SP flooding combined with SmartWater achieved higher oil recovery with less chemical consumption when compared to conventional SP flooding.

Combining Micro-CT Images with NMR and MICP for evaluating pore connectivity and its impact on Enhanced Oil Recovery in Carbonates

Combining Micro-CT Images with NMR and MICP for evaluating pore connectivity and its impact on Enhanced Oil Recovery in Carbonates

Experimental study and surface complexation modeling of non-monotonic wettability behavior due to change in brine salinity/composition: Insight into anhydrite impurity in carbonates

Wettability alteration as the main mechanism of improved oil recovery in carbonates during low salinity/engineered water flooding (LS/EWF) is a complex phenomenon due to high heterogeneity of rock. During LS/EWF, wettability changes when electrochemical interactions at carbonate-brine interface happen. Anhydrite impurity in carbonates is one of the most important parameters affecting the electrochemical interactions at the rock-brine interface and the wettability alteration process. Therefore, the success of LS/EWF in carbonate reservoirs lies in perceiving the role of impurities such as anhydrite, from a geochemical and dissolution point of view.Modified flotation tests (MFT) were performed on two rock samples (calcite and a mixture of calcite and 10 wt% of anhydrite) to assess the wettability alteration which showed a non-monotonic wettability effect as the presence of anhydrite lowered the optimum salinity from 10-times diluted seawater (SW/10) to SW/25. Mineral dissolution and zeta potential measurement showed no comprehensive correlation with the wettability state of particles obtained from MFTs. To resolve this challenge, a diffuse double layer (DDL) based surface complexation model (SCM) was developed using PHREEQC geochemical package to shed light on the anhydrite role during the desorption of oil acidic components from the rock surface imposed on various brines. The model was validated using measured zeta potential. The DDL-based SCM proposed an anhydrite dominant window in which the presence of anhydrite, its dissolution, and in-situ supply of SO42-, lead to altering the wettability to more water wetness.This work is significant to explain the effect of anhydrite impurity on the performance of low salinity water injection using experimental data and DDL-based SCM, while the simple techniques of rock dissolution and zeta potential are not able to justify the non-monotonic behavior of wettability of the carbonates. Also, it introduces a new quantitative parameter of the wettability state of carbonate surface by considering the adsorbed carboxylic acid components on the calcite surface reported by SCM.

Effect of Total Acid Number and Recovery Mode on Low-Salinity Enhanced Oil Recovery in Carbonates

Summary Low-salinity water (LSW) flooding is an attractive enhanced oil recovery (EOR) option, but its mechanism leading to EOR is poorly understood, especially in carbonate rock. In this paper, we investigate the main reason behind two tertiary LSW coreflood tests that failed to demonstrate promising EOR response in reservoir carbonate rock; additional oil recovery factors by the LSW injection were only +2% and +4% oil initially in place. We suspected either the oil composition (lack of acid content) or the recovery mode (tertiary mode) was inappropriate. Therefore, we repeated the experiments using an acid-enriched oil sample and injected LSW in the secondary mode. The result showed that the low-salinity effect was substantially enhanced; the additional oil recovery factor by the tertiary LSW injection jumped to +23%. Moreover, it was also found that the secondary LSW injection was more efficient than the tertiary LSW injection, especially in the acid-enriched oil reservoir. In summary, it was concluded that the total acid number (TAN) and the recovery mode appear to be the key successful factors for LSW in our carbonate system. To support the conclusion, we also performed contact angle measurement and spontaneous imbibition tests to investigate the influence of acid enrichment on wettability, and moreover, LSW injection on wettability alteration.

Electro-kinetically tailored interfaces for chemical enhanced oil recovery in carbonates

SmartWater flooding through the injection of optimized chemistry water has lately become an attractive proposition for improved/enhanced oil recovery (IOR/EOR) in carbonate reservoirs. The wettability alteration towards water-wet conditions caused by favorable surface charge alteration is identified as the main mechanism responsible for oil recovery. In this experimental investigation, the impact of SmartWater/surfactant synergy on wettability alteration was thoroughly studied by measuring zeta-potentials at calcite/brine and crude oil/brine interfaces using electrophoresis technique. Different types of surfactants are considered including: anionic, amphoteric and non-ionic. Four different low salinity water recipes including SmartWater (10-times reduced high salinity water) as well as the high salinity water (HSW) were chosen for zeta potential measurements. The results showed that both anionic surfactants increased the magnitude of the negative zeta-potentials at the interfaces by almost same order of magnitude. The negative zeta-potentials were increased the most with anionic surfactants in the low salinity NaCl brine, from (−15 to −21 and up to −37 mV) at the calcite interface and from (−6 to −19 mV) at the oil interface. SmartWater showed relatively higher negative zeta-potentials for calcite when compared to low salinity Na2SO4 brine and HSW in the presence of anionic surfactant. These results indicate that both NaCl brine and SmartWater can synergistically combine with anionic surfactants for effective wettability alteration in carbonates. Amphoteric surfactant showed a negligible impact on electrical double layer (EDL) expansion and consequently the wettability alteration. The nonionic surfactant induced electrostatic repulsion forces at both calcite/brine by shifting the zeta potentials from (+5.9 to −6.3 mV) and crude oil/brine interface from (−0.2 to −4.7 mV) respectively in high salinity water. As a result, nonionic surfactant can be considered as the best chemical formulation to reduce interfacial tension and cause wettability alteration in conventional chemical flooding processes. The negligible impact of adding surfactant chemicals on the measured di-electric constant of different brines confirmed the robustness of zeta-potential values reported in this study. This work for the first time evaluated the synergistic effects of different brines including the SmartWater with surfactant chemicals by measuring zeta-potentials at calcite/brine and oil/brine interfaces. The optimally suited water recipes were identified to synergistically combine with these chemicals to enhance wettability alteration in carbonates. The new knowledge gained from this electro-kinetic study will provide practical guidance on how to design efficient chemical flooding processes for wettability alteration and enhanced oil recovery in carbonates.

Experimental Investigation of the Effect of Acid and Base on Wettability Alteration of a Calcite Surface

Wettability alteration toward a favorable wetting condition is one major mechanism of enhancing oil recovery in carbonates. Obtaining the desired wettability stipulates that a clear understanding of the original wetting properties of the rock surface be provided. In fact, the aim of this study is to elucidate the effect of acid and base upon the wettability alteration of a calcite surface by investigating the individual effects of an organic acid (stearic acid) and a base (N,N-dimethyldodecylamine, N,N-DMDA) at different concentrations as well as their combinations on calcite wetting properties. Contact angle, ζ-potential, Fourier transform infrared spectroscopy, and thermogravimetric analysis (TGA) were conducted to determine changes in wetting properties of the calcite surface. Moreover, interfacial tension (IFT) measurements were used to evaluate the interfacial activity of the model oil systems. Overall, the results revealed that by increasing the acid concentration, wettability of a calcite surface shifted toward more oil-wetness and adsorption of stearic acid on a calcite surface increased. Treating calcite surfaces with the base revealed that a low concentration of N,N-DMDA was able to shift the calcite wettability from a water-wet state to a slightly oil-wet state. In addition, TGA results showed low adsorption of the base with a high surface area occupied by the base molecule, indicating a horizontal orientation of the base on the calcite surface. For acid–base mixtures, at a constant acid concentration, the wettability alteration toward oil-wetness increased in the presence of the base, as the base-to-acid ratio increased up to 1, as a result of which oil-wetness decreased. Moreover, IFT measurements indicated lower IFT of acid–base mixtures compared to those of individual acidic and basic model oil solutions, which could be attributed to the synergistic effect between the acid and base by forming acid–base complexes. The presence of the base hindered acid adsorption on the calcite surface. However, the basic component could contribute to wettability alteration by forming acid–base complexes. These complexes could adsorb on the calcite surface and affect its wetting preferences. In addition, the base molecules may adsorb on the calcite surface at high base-to-acid ratios. The results suggested that the ratio of base to acid would determine the contribution of acid molecules, base molecules, and acid–base complexes in wettability alteration of calcite surfaces. Hence, possible mechanisms of wettability alteration by acid–base combinations were proposed at different base-to-acid ratios.

Improved Oil Recovery in Carbonates by Ultralow Concentration of Functional Molecules in Injection Water through an Increase in Interfacial Viscoelasticity.

Injection of sea water is the most common practice to displace oil in porous media in subsurface formations. In numerous studies, conventional surfactants at concentrations in a range of one weight percent have been proposed to be added to the injected water to improve oil recovery. Surfactants accumulate at the oil-water interface and may reduce the interfacial tension by three orders of magnitude or more, resulting in higher oil recovery. Recently, we have proposed the addition of ultralow concentration of a non-ionic surfactant to the injected water to increase interface viscoelasticity as a new process. The increase in interface viscoelasticity increases oil recovery from porous media. This alternative approach requires only a concentration of 100 ppm (two orders less than the conventional improved oil recovery) and therefore is potentially a much more efficient process. In this work, we present a comprehensive report of the process in an intermediate-wet carbonate rock. There is very little adsorption of the functional molecules to the rock surface. Because the critical micelle concentration is low (around 30 ppm), most of the molecules move to the fluid-fluid interface to form molecular structures, which give rise to an increase in interface elasticity. We also demonstrate that interface elasticity has a non-monotonic behavior with the salt concentration of injected brine, and an optimum salinity exists for maximum oil recovery.

Influence of water composition on formation damage and related oil recovery in carbonates: A geochemical study

Several benefits of low salinity/engineered water injection (LSWI/EWI) have been reported in the literature including its ability to increase oil recovery at low cost and with least environmental impact. Nevertheless, the related reservoir-engineering problems to this technique such as formation damage is still uncertain and has not been thoroughly investigated. This study investigates the effect of water composition on formation damage and the related oil recovery from a geochemical prospective.The study presents coupling of the IPhreeqc geochemical engine with Matlab to simultaneously solve the oil-water multiphase flow in 1-D and the related geochemical reactions. Using this coupling technique, the geochemical capabilities of Phreeqc were successfully incorporated in a multiphase flow simulator. The latter enabled modeling of reactive transport and formation damage in subsurface multiphase reservoir. The developed model was validated against single phase geochemical simulator, analytical solution of Buckley-Leverette equation, commercial reservoir engineering simulator, and experimental data. The results showed that the temperature, sulfate concentration, and dilution of injection water have a pronounced effect on formation dissolution and precipitation during LSWI/EWI. Also, anhydride scale is the main controlling solid specie for formation damage in the investigated case study. In addition, high temperature water injection should be avoided in carbonate reservoirs due to the likelihood of anhydride precipitation and formation damage. This precipitation occurs because of the low-solubility of anhydride at high temperature. Moreover, water dilution could decrease scale formation while sulfate spiking might increase anhydride precipitation. Hence, sulfate concentration should be optimized as a wettability alteration agent to enhance oil recovery while avoid formation damage. Furthermore, as a sequence of anhydride precipitation by sulfate spiking, oil production is expected to decrease by around 10% in the selected case study. The dissolution and precipitation mechanisms during LSWI/EWI are very case-dependent and hence, the findings of this study cannot be generalized.

Linking pore scale mechanisms with macroscopic to core scale effects in controlled ionic composition low salinity waterflooding processes

The controlled ionic composition low salinity waterflooding processes through tuning of salinity and ionic composition are lately becoming popular for oil recovery in carbonates. Most of the experimental work reported in this area has been limited to macroscopic and core scale measurements and these results consensually pointed out wettability alteration towards water-wet state to be the main recovery mechanism. It is widely believed that wettability is the macroscopic to core scale effect and the link between such effects with molecular scale interactions and phenomena occurring at both carbonate-oil/brine and oil-brine interfaces is not yet well understood. The current study aims to address this knowledge gap by acquiring data on various crude oil/brine/carbonate and crude oil-brine physicochemical interactions using several macroscopic, pore, and core scale experimental techniques. These techniques include contact angle, zeta potential, cryo-broad ion beam scanning electron microscope (BIB-SEM), sum frequency generation (SFG) spectroscopy, and core flooding relative permeabilities. Both high salinity water (HSW) and a controlled ionic composition low salinity water (CICLSW) containing sufficient amount of three key ions (sulfates, magnesium, and calcium) are used to delineate water chemistry effects on resulting physicochemical interactions and changes occurring at carbonate-oil/brine and oil-brine interfaces.The macroscopic contact angle data showed strongly oil-wet behavior with HSW and favorable wettability alterations towards water-wet conditions with CICLSW. The opposing polarity of zeta potentials is observed at calcite/brine and oil-brine interfaces with HSW, which can collapse the thin water film and cause the direct contact of crude oil on to the rock surface to result in oil-wetness. In contrast, CICLSW showed increasingly negative zeta potentials at oil/brine interface and the polarity reversal to negative zeta potentials across calcite/brine interface to stabilize the water-film on the rock surface and subsequently render water-wet conditions. The cryo-BIB-SEM imaging showed trapping of oil ganglia in larger pores and relatively less contact of crude oil with carbonate surface for CICLSW flooded sample. The phase distributions in the sample further confirmed less amount of oil trapped in carbonate pores, which provides a clear indication of CICLSW effect on wettability alteration and better oil mobilization in carbonates. It is also understood from sum frequency generation spectroscopy CH3/CH2 stretching results that CICLSW increased the conformation order of hydrocarbon chains to enhance the interactions at thin interfaces and ultimately alter the wettability. Significant increase in the intensities of free OH stretches and hydrogen bonding are observed at oil/water interface with CICLSW. Such result provides a direct indication that dissolved salt ions displace some water molecules at the interface, resulting in reduced free OH bond densities to correlate well with zeta potential drop observed in HSW. The shifts in relative permeability curves obtained by history matching the coreflood experimental data also confirmed the favorable effect of CICLSW in altering the wettability towards water-wet conditions. This study thereby establishes a good agreement between macroscopic to core scale effects and pore scale interactions occurring at carbonate-oil/brine and oil-brine interfaces to clearly demonstrate the beneficial effects of CICLSW on wettability alteration and oil recovery in carbonates.

Dilute surfactants for wettability alteration and enhanced oil recovery in carbonates

The effectiveness of dilute nonionic surfactant was evaluated in this study for wettability alteration and enhanced oil recovery (EOR) in carbonates by performing a suite of measurements such as aqueous stability, surface tension, phase behavior, interfacial tension (IFT), zeta potential, contact angle, and microscopic dynamic oil liberation. Two different brines, low salinity and high salinity, were used at 0.1 wt% surfactant concentration. These measurements were conducted at elevated temperature using the rock and crude oil samples from a carbonate reservoir. The dilute concentration of polymer has also been used together with surfactant in both high salinity and low salinity brines to quantify the effects of wettability alteration on microscopic oil liberation efficiency in carbonates.The compatibility of nonionic surfactant was demonstrated in high salinity brine at reservoir temperature. The critical micelle concentrations were found to be very low in both low salinity and high salinity brines. The phase behavior results showed the formation of middle phase microemulsion and correspondingly low interfacial tensions in high salinity brine. The contact angle data indicated the ability of nonionic surfactant to significantly alter the wettability of carbonate from oil-wet to either intermediate wet or less oil-wet in high salinity brine whereas only marginal wettability alterations from oil-wet to less oil-wet were obtained in low salinity brine. The increasing negative zeta potentials and the alteration of charge polarity from positive to negative were observed at crude oil-brine and calcite/brine interfaces, respectively due to surfactant in the high salinity brine. The microscopic equilibrium degree of crude oil liberation from carbonate surface was found to be about 20% higher with high salinity surfactant-polymer solution when compared to the low salinity surfactant-polymer solution. Such higher oil release efficiency obtained with high salinity surfactant-polymer solution can be attributed to the beneficial effects of surfactant induced wettability alteration and IFT reduction mechanisms in the high salinity brine to favorably alter both capillary and adhesion forces for efficient EOR in carbonates.

Effects of low salinity water on calcite/brine interface: A molecular dynamics simulation study

Calcite is among the most abundant minerals organizing the oil reservoir formation and therefore its surface properties play a central role in the increase of the oil recovery efficiency. The effect of low-salinity water in carbonate rocks reveals that brine composition and salinity can improve the oil recovery in carbonates through wettability alteration. However, the specific mechanism for wettability changes that leads to improved oil recovery in calcite is not well understood. To obtain deeper insights at atomic level into the understanding the characteristics of the calcite-water interface, we performed classical molecular dynamics simulations in the presence of different ions in brine solutions in the oil reservoirs. The results showed highly ordered water layer in the vicinity of calcite surface, followed by subsequent layers rich in ions of brine. These layers form an electric double layer, with monovalent Na+ ions in the Stern layer and anions in the diffuse layer. The results also indicated that divalent cations do not appear in the electric double layer. The appearance of ions at calcite/brine interface is more effective in wettability alteration for low saline brines such as seawater than high saline ones like formation water validating the applicability of low saline water injection method to improve oil recovery efficiency.

Insights into the Impact of Temperature on the Wettability Alteration by Low Salinity in Carbonate Rocks

It has been proposed that increased oil recovery in carbonates by modification of ionic composition or altering salinity occurs mainly at a temperature exceeding 70–80 °C. The argument was that elevated temperatures enhance adsorption of the potential determining ions which then modifies wettability to a less-oil-wetting state. According to this rationale, it becomes questionable if diluted brines or brines without these ions can be still applicable. Therefore, the aim of this paper is to investigate if the wettability alteration truly depends on temperature and if so how the trend with temperature can be explained. We followed a combined experimental and theoretical modeling approach. The effect of brine composition and temperature on carbonate wettability was probed by monitoring contact angle change of sessile oil droplets upon switching from high salinity to lower salinity brines. IFT measurements as a function of salinity and temperature along with extensive ζ-potential measurements as a function of ...

Oil recovery and wettability alteration in carbonates due to carbonate water injection

Enhanced oil recovery in carbonates due to wettability alteration has received much attention recently. In contrast to sandstones reservoirs, carbonates are neutral-wet or preferentially oil-wet. The use of CO2 dissolved into water has emerged as an alternative method for EOR operations in carbonates reservoirs. In the present paper, oil recovery from two carbonate outcrop rocks was evaluated with different brines containing CO2. The evaluation included a qualitative approach by spontaneous imbibition tests and a quantitative assessment by the Amott–Harvey index. The rocks tested were limestone and dolomite samples known as analogous to Brazilian pre-salt reservoirs. The testing fluids were a medium gravity crude oil, seawater concentration brine, formation equivalent brine and the carbonated version of these brines. Results shown additional oil recovery directly associated with wettability alteration driven by brine concentration switches. Oil recovery increases were observed independently if the brine concentration decreased or increased over the water replacement process. Wettability alteration took place in both carbonate types starting at oil-wet to neutral-wet conditions. Similar tests carried out with equivalent carbonated brines showed similar alterations in the wetting properties, trending no dependence on salt concentration. However, CO2 and its derived ions dissolved in the brines seem to inhibit the wettability alteration mechanism.

Novel Application of the Flotation Technique To Measure the Wettability Changes by Ionically Modified Water for Improved Oil Recovery in Carbonates

The accurate determination of the wetting condition of carbonate reservoirs is a prerequisite for the selection of any enhanced oil recovery (EOR) fluid. Most carbonate formations are initially oil-wet to intermediate-wet at reservoir conditions. In order to correctly chose an EOR fluid to alter the wettability, we need to understand the initial wetting conditions and design an ionically modified water (advanced water) to alter wettability and improve oil recovery. If a reservoir has already been reached to the optimum wetting conditions by injecting formation water or any other fluid, then there is no need for ionically modified water. A number of methods have been devised to identify the wetting conditions including contact angle measurements, spontaneous imbibition, and chromatographic separation, etc. But contact angle measurement requires surfaces that lack natural surface roughness, spontaneous imbibition tests take months, and chromatographic separation is feasible only for core flooding in sulfate...

Potential of Low-Salinity Waterflood To Improve Oil Recovery in Carbonates: Demonstrating the Effect by Qualitative Coreflood

Summary Low-salinity waterflood (LSF) is a promising improved-oil-recovery (IOR) technology. Although, it was demonstrated that LSF is an efficient IOR method for many sandstone reservoirs, the potential of LSF in carbonate reservoirs is still not well-established because only a limited number of successful coreflood experiments are available in the literature. Therefore, the aim of this study was to examine the oil-recovery improvement by LSF in carbonate reservoirs by performing coreflood experiments. This paper proposes an experimental approach to qualitatively evaluate the potential of LSF to improve oil recovery and alter the rock wettability during coreflood experiments. The corefloods were conducted on core plugs from two Middle Eastern carbonate reservoirs with a wide variation of rock properties and reservoir conditions. Seawater (SW) and several dilutions of formation brine and SW were flooded in the tertiary mode to evaluate their impacts on oil recovery compared with formation-brine injection. In addition, a geochemical study was performed with PHREEQC software (Parkhurst and Appelo 1999) to assess the potential of calcite dissolution by LSF. The experimental results confirmed that lowering the water salinity can alter the rock wettability toward more water-wet, causing improvement of oil recovery in tertiary waterflood in plugs from the two reservoirs. Furthermore, SW is more-favorable for improved oil recovery than formation brine because injection of SW after formation brine resulted in extra oil production. This demonstrates that the brine composition plays an important role during waterflooding in carbonate reservoirs, and not only the brine salinity. It was also observed that oil recovery can be improved by injection of brines that cannot dissolve calcite on the basis of the geochemical modeling study. This implies that calcite dissolution is not the dominant mechanism of IOR by LSF. To conclude, this paper demonstrates that LSF has a good potential as an IOR technology in carbonate reservoirs. In addition, the proposed experimental approach ensures the verification of LSF effect, either it is positive or negative. However, further research is required to explore the optimum salinity and composition and the most-influential parameters affecting LSF response.

Geochemical Interpretation of Low-Salinity-Water Injection in Carbonate Oil Reservoirs

Summary The advantages of using the low-salinity-water-injection (LSWI) technique to improve oil recovery in carbonates are reported in the literature; however, the mechanism behind it is still uncertain. This paper represents a comparison between two geochemical simulators [UTCHEM (UTCHEM manual, 2000) and PHREEQC (Parkhurst and Appelo 2013)] through modeling fluid- and solid-species concentrations of a recently published LSWI coreflood. Moreover, an attempt to interpret the mechanism controlling the LSWI effect on oil recovery from carbonates is presented on the basis of the findings of this work. The LSWI technique is case-dependent, and hence, the findings cannot be generalized.

Insights into the Mechanism of Wettability Alteration by Low-Salinity Flooding (LSF) in Carbonates

The low-salinity effect (LSE) in carbonate rock has been less explored in comparison to sandstone rock. Laboratory experiments have shown that brine composition and (somewhat reduced) salinity can have a positive impact on oil recovery in carbonates. However, the mechanism leading to improved oil recovery in carbonate rock is not well understood. Several studies showed that a positive low-salinity flooding (LSF) effect might be associated with dissolution of rock; however, because of equilibration, dissolution may not contribute at reservoir scale, which would make LSF for carbonate rock less attractive for field applications. This raises now the question whether calcite dissolution is the primary mechanism of the LSF effect. In this paper, we aim to first demonstrate the positive response of carbonate rock to low salinity and then to gain insight into the underlying mechanism(s) specific to carbonate rock. We followed a similar methodology as in sandstone rock [Mahani, H.; Berg, S.; Ilic, D.; Bartels, W....

Optimization Study of a Novel Water-Ionic Technology for Smart-Waterflooding Application in Carbonate Reservoirs

Summary Injection water with selective ionic content and composition is a key requirement for smart-waterflooding (SWF) application in carbonate reservoirs. Smart water--depleted in monovalent ions, but enriched in sulfates and divalent cations--is desired for incremental oil recovery in carbonates, which constitute complex water chemistry when compared with sandstones. Most of the published work available in this area is focused on addressing water-chemistry requirements for low-salinity waterflooding in sandstones. However, none of these studies describes the complex injection-water requirements of SWF in carbonate reservoirs. Also, injection-water chemistry has a known impact on several tertiary enhanced-oil-recovery (EOR) processes among the three major categories of chemical, gas, and thermal EOR. The main purpose of this study is, therefore, to identify and optimize a novel water-ionic technology that can serve as a “one-shop solution” to generate desired water chemistries suited for different improved-oil-recovery (IOR)/EOR processes, including SWF in carbonates. A novel water-ionic technology, comprising nanofiltration and reverse-osmosis membrane-based processes, was identified for optimization in this study. The proposed technology makes use of these two membrane-desalination processes in parallel configuration to provide multiple water streams of widely varying ionic strength and content. Different water streams obtained from this novel solution can be blended effectively to yield a smart-water cocktail of desired ionic strength, composition, and monovalent- to divalent-ion content suited for carbonates. Smart-water cocktails obtained from the proposed solution are also suited for application in other EOR processes such as polymer flooding, alkaline/surfactant/polymer flooding, low-salinity surfactant flooding, dilute surfactant flooding, carbonated waterflooding, and miscible gasflooding, and are suited for boiler feedwater in steamflooding. The optimized scheme thereby offers a novel one-shop solution to meet the complete suite of desired water-chemistry requirements for different IOR/EOR processes. In addition, comparative evaluation-study results between novel water-ionic technology and other already-known advanced-desalination schemes highlight the major advantages of the new solution in terms of better water-ion-tuning flexibility, higher recovery efficiency, lower energy requirement/footprint, and ease of operation.

Mysteries behind the Low Salinity Water Injection Technique

Low salinity water injection (LSWI) is gaining popularity as an improved oil recovery technique in both secondary and tertiary injection modes. The objective of this paper is to investigate the main mechanisms behind the LSWI effect on oil recovery from carbonates through history-matching of a recently published coreflood. This paper includes a description of the seawater cycle match and two proposed methods to history-match the LSWI cycles using the UTCHEM simulator. The sensitivity of residual oil saturation, capillary pressure curve, and relative permeability parameters (endpoints and Corey’s exponents) on LSWI is evaluated in this work. Results showed that wettability alteration is still believed to be the main contributor to the LSWI effect on oil recovery in carbonates through successfully history matching both oil recovery and pressure drop data. Moreover, tuning residual oil saturation and relative permeability parameters including endpoints and exponents is essential for a good data match. Also, the incremental oil recovery obtained by LSWI is mainly controlled by oil relative permeability parameters rather than water relative permeability parameters. The findings of this paper help to gain more insight into this uncertain IOR technique and propose a mechanistic model for oil recovery predictions.