Oil-wet Carbonate Research Articles

New Insights into the Application of a Magnetic Field to Enhance Oil Recovery from Oil-Wet Carbonate Reservoirs

Given recent moves toward cleaner energy production, the application of environmentally friendly methods for enhanced oil recovery (EOR) is considered to be an important research strategy in increasing oil production from existing hydrocarbon reservoirs. Therefore, in this article, the application of a magnetic field is introduced for the first time as a novel and eco-friendly EOR technique for oil-wet carbonate reservoirs. The magnetic field is generated using three different magnet strengths of 3000, 4100, and 6000 Gauss (G). The impact of incremental increases in the magnetic field on oil production from Austin chalk is investigated through measurements of the contact angle (CA), rock compaction, spontaneous imbibition (SI) of water, and the monitoring of the rock surface streaming potential. Dynamic CA measurements on oil-wet chalk surfaces in the presence of a magnetic field show that the value of CA is reduced faster than when a magnetic field is absent, indicating a significant increase in water im...

Experimental investigation on new derived natural surfactant: wettability alteration, IFT reduction, and core flooding in oil wet carbonate reservoir

ABSTRACT It is necessary to enhance oil production from reservoir due to increase of the fossil fuel consumption that results of industrial life development. Surfactant flooding is a popular method to enhance oil recovery by IFT reduction and wettability alteration. In this study, a new natural surfactant that extracted from Cordia myxa leaf is used for surfactant flooding. The effect of this natural surfactant on IFT and wettability is investigated experimentally. Then, surfactant flooding is applied in a carbonate core sample. The results show the IFT of solution was reduced from 33/28mN/M at 0 wt% to 16.24 mN/M at 6 wt% by increasing natural surfactant concentration. More than, contact angle was decreased from 137.05° at 0 wt. % to 130.65° at 5.5 wt. %. The core flooding results show C. myxa flooding increased 27% more oil recovery compared to water flooding and reduced residual oil saturation in porous media. The results show C. myxa can be applicable as a green surfactant for enhancing oil recovery.

Insights into stability of silica nanofluids in brine solution coupled with rock wettability alteration: An enhanced oil recovery study in oil-wet carbonates

Stability of nanoparticle dispersion in brine solution is a key parameter for a successful nanofluid- based enhanced oil recovery processes. This paper aims to provide a systematic laboratory study to investigate the stability of silica nanoparticles (NPs) in presence of mono and divalent salts, namely NaCl and MgCl2, coupled with their potential to alter wettability of low-permeable, oil-wet carbonates at 80 °C. First, silica nanofluids with different salt concentrations were prepared using sonication process. Results showed that presence of divalent cations significantly hinders the stability of silica nanofluids as compared to monovalent ones. It was found that most of silica NPs was precipitated in presence MgCl2 even at a low concentration of 2000 ppm while no particle precipitation was observed with 10,000 ppm NaCl over a two- week period. This was in line with a smaller particle size of silica NPs with 10,000 ppm NaCl (73 nm) as compared to MgCl2, 388 nm. Also, we found a noticeable reduction in zeta potential of silica nanofluids with MgCl2, −8 mV, as compared to NaCl, −25 mV. This reveals that the negative surface charge of silica NPs became more neutralized in presence of MgCl2 and thus more chance for agglomeration of silica NPs through the aqueous phase. As to rock- nanofluid interaction, silica nanofluids in presence of NaCl exhibited a higher potential to alter rock wettability to more water-wetness than MgCl2. Such wettability alteration was discussed in terms of adsorption of silica NPs on the carbonate rock followed by a generation of thin layer of silica NPs on the rock surface, leading to an extra pressure on oil droplet. This was in line with SEM- EDX analyses indicting that silica NPs covers the carbonate rock surface. In terms of oil recovery, imbibition of silica nanofluid containing 10,000 ppm NaCl provided 14% incremental oil while the lowest oil recovery was obtained for silica nanofluids containing MgCl2 due to their less stability. These results showed that there could be a correlation between the stability of silica nanofluids and their EOR potential, which is strongly dependent on the salt type and concentration.

Optimal Zwitterionic Surfactant Slug for an Improved Oil Recovery in Oil Wet Carbonate Rocks

Of recent, there has been research and development in the technologies/techniques required to meet the ever-growing energy demand in the world. Oil is a major source of energy which is contained in over 50% of carbonate reservoirs. The oil/mixed wettability of carbonate rocks makes it technically challenging to recover the needed oil. The process of crude oil recovery has three different stages primary, secondary and tertiary recovery. Tertiary recovery is also known as enhanced oil recovery or EOR. EOR includes the use of surfactants to reduce the interfacial tension between a hydrocarbon and brine, thus suspending them both in a microemulsion. Surfactant performance can be affected by multiple variables, including brine salinity, surfactant concentration, and type of hydrocarbon. A petroleum engineer must take all variables into consideration when selecting a surfactant to make sure that its efficiency is as high as possible, especially because the use of surfactants is costly.
 In this work, a chembetaine zwitter ionic surfactant of two different concentrations are evaluated at various synthetic formation brine salinities for their favourable wettability alteration and interfacial tension reduction in oil-wet carbonate- Silurian Dolomite. For the evaluation, fluid-fluid and rock-fluid analysis are carried out to select the optimal surfactant concentration and brine salinity with the greatest improved oil recovery potential.
 Results are indicative that the surfactant at the two concentrations studied is compatible at the ranges of salinities evaluated. However, from the fluid-fluid analysis, there was no ultra-low interfacial tension that is needed for oil mobilization. More so, the rock-fluid analysis shows that the surfactant is not able to alter the wettability of oil-wet rocks favourably. The optimal surfactant slug for the greatest oil recovery, in this case, would be expected at 0.5% surfactant concentration in 10,000 ppm synthetic formation brine salinity. This study, therefore, serves as a guide for the design of optimal surfactant slug in oil-wet carbonate cores requires to reduce non-productive time, prevent reservoir damage and therefore improve recovery.

Optimal Zwitterionic Surfactant Slug for an Improved Oil Recovery in Oil Wet Carbonate Rocks - Silurian Dolomite

The increase in energy demand has led to extensive research and development on economically, environmentally and technically feasible ways of improving the ever-growing energy demand. A common derivative of energy is from hydrocarbons, specifically oil. The process of oil recovery can be divided into primary, secondary, and tertiary recovery (also known as enhanced oil recovery). Once the internal pressure of a reservoir has depleted enough during primary and secondary recovery, more advanced techniques in enhanced oil recovery mechanisms are used to recover 50-80% of oil in the reservoir. Tertiary recovery includes the use of surfactants to reduce interfacial tension (IFT) or alter wettability. In this work, a zwitter ionic surfactant at two different concentrations is evaluated for its ability to reduce the interfacial tension between oil and water, as well as altering wettability in silurian dolomite. To achieve this, fluid-fluid analysis was done by a compatibility test, phase behavior test and interfacial tension measurements. Rock-fluid analysis was also completed by means of floatation test, carried out with carbonate rock particles to analyze the surfactant’s ability to alter wettability. Solution pH measurements were taken to validate the qualitative floatation test results. Results show that the surfactant, chembetaine C surfactant, is compatible with all ranges of salinities investigated, though was not able to produce a winsor type III micro-emulsion. The results of the interfacial tension measurements are in line with the phase behavior test, as none of the measurements were at ultra-low values. Surfactant retention is likely to occur with the analyzed zwitterionic surfactant based on the fluid-fluid analysis. Qualitative results from the floatation test show that the wettability of the carbonate rock particles cannot be significantly altered to more water-wet conditions. The pH of the solution remains at alkaline values, which can be beneficial in enhanced oil recovery in producing soap in situ, also known as saponification. Overall, tests conclude that this zwitterionic surfactant at 1% concentration would be most effective at 10,000 ppm salinity brine, though overall is not suitable for chemically enhanced oil recovery.

Micro-scale experimental investigations of multiphase flow in oil-wet carbonates. II. Tertiary gas injection and WAG

Carbonate reservoirs are typically oil-wet, which can lead to low oil production during the oil recovery processes such as base waterflooding. The residual oil in these reservoirs is the target of many EOR techniques such as tertiary gas injection and Water-Alternating-Gas (WAG) flooding. Currently, there is scarce research investigating the pore-scale displacement physics governing the afore-mentioned EOR techniques in oil-wet carbonates. In this study, three sets of miniature core-flooding experiments were performed in carbonate samples at elevated pressure and temperature conditions using a three-phase core-flooding system integrated with a high-resolution X-ray micro-CT scanner. Pore-scale displacement events governing tertiary gas injection and WAG under weakly oil-wet conditions were examined. The prevailing oil mobilization mechanisms during the tertiary gas injection were further investigated under varying wettability conditions. The results revealed that gas-to-oil-to-brine double displacement is the main displacement chain for oil production by tertiary gas injection. During this process, the greater was the degree of oil-wetness of the rock, the larger became the additional oil recovery that could be achieved. This was due to the increase in the frequency of gas-to-oil-to-brine double displacements and the superior connectivity of the oil phase under stronger oil-wet conditions. Furthermore, WAG flooding significantly increased the displacement efficiency of both gas and brine phases because of the shielding effect of the trapped gas ganglia. In the first WAG cycle, oil was produced through a series of direct and double displacements. Multiple displacements started taking place and further contributed to oil recovery as more WAG cycles were implemented.

Micro-scale experimental investigations of multiphase flow in oil-wet carbonates. I. In situ wettability and low-salinity waterflooding

In this study, the impacts of temperature, initial water saturation, and aging time on wettability alteration during dynamic aging process were investigated at the pore scale, using a state-of-the-art high-temperature, high-pressure miniature core-flooding system integrated with a high-resolution micro-CT scanner. Furthermore, pore-scale displacement mechanisms impacting the waterflooding oil recovery under varying oil-wet conditions were probed. Subsequently, we investigated the wettability alteration and its corresponding impact on pore-scale displacement mechanisms during low-salinity waterflooding (LSWF). The results showed that the aging-induced wettability alteration reached an equilibrium condition after approximately seventeen days. With higher temperature, lower initial water saturation, and longer aging time, we observed greater in situ contact angles indicative of more oil-wet rock surfaces. Once brine was injected to displace oil, since the majority of pore elements were oil-wet after the aging process, pore-scale piston-like displacements (brine-to-oil drainage) had the largest contribution to the oil recovery. Based on our observations, the waterflooding-based oil recovery decreases as the porous medium becomes more oil-wet. This phenomenon is due to the higher threshold brine pressures of the displacements in more oil-wet conditions, which restricts brine invasion into medium and small size pores. Furthermore, wettability alteration towards neutral-wetness and the consequent reduction in threshold brine pressure required for the fluid to invade the midsize oil-filled pores, result in higher oil recovery by LSWF compared to high-salinity waterflooding (HSWF). The in situ analyses indicate that reservoirs with wide pore size distributions (a large number of midsize pores) could be better candidates for applications of LSWF EOR technique.

Wettability alteration of oil-wet carbonate surface induced by self-dispersing silica nanoparticles: Mechanism and monovalent metal ion's effect

Various analysis methods including IR, SEM, contact angle determination and spontaneous imbibition experiments were used to investigate the mechanism of wettability alteration of oil-wet carbonate surface by silica nanoparticles (NPs) in the present study. Stable silica nanofluids were first studied through zeta potential measurement. Results show that there is an optimal sonication time interval (5 h) for the preparation of SiO2 nanofluid after the magnetic stirring treatment in this work. The addition of NaCl can decrease the dispersion stability of SiO2 nanofluids. Both IR and SEM results show that the originally water-wet silica NPs are adsorbed on the calcite surface, making the surface water-wet. The role of sodium ions is to compress the electric double layer, giving the nanoparticle (NP) an opportunity to access the palmitic acid molecules. The palmitic acid molecules are replaced by the NPs through competitive adsorption. The longer the contact time, the better the performance of wettability alteration of oil-wet carbonate rock by the nanofluid. The contact angle decreases as the NPs concentration increases. Among the metal ions in the formation water, Na+ ion is closest to the solid surface, making Na+ ion have a great influence on wettability change of oil-wet carbonate surface by silica NP. Na+ ions in the solution can neutralize some negatively charged portion of the carbonate surface, making the adsorption amount of silica NPs on the solid surface increase. Thus, wettability alteration of oil-wet carbonate surface by SiO2 NPs is improved in the presence of Na+ ions. During the spontaneous imbibition experiments, silica NPs are adsorbed on rock surface and gradually form a wedge film in the contact area of the three-phase (oil-water-solid). In this case, structural disjoining pressure is generated due to the presence of electrostatic repulsion and Brownian motion of silica NPs. When the structural disjoining pressure is stronger than the oil droplet adhesion, the contact area of oil droplet on the solid surface gradually decreases, making the oil droplet eventually peel off from the rock surface.

Ultralow-Interfacial-Tension Foam-Injection Strategy in High-Temperature Ultrahigh-Salinity Fractured Oil-Wet Carbonate Reservoirs

Summary Oil recovery in many carbonate reservoirs is challenging because of unfavorable conditions, such as oil–wet surface wettability, high reservoir heterogeneity, and high brine salinity. We present the feasibility and injection–strategy investigation of ultralow–interfacial–tension (IFT) foam in a high–temperature (greater than 80°C), ultrahigh–formation–salinity [greater than 23% total dissolved solids (TDS)] fractured oil–wet carbonate reservoir. Because a salinity gradient is generated between injection seawater (SW) (4.2% TDS) and formation brine (FB) (23% TDS), a frontal–dilution map was created to simulate frontal–displacement processes and thereafter it was used to optimize surfactant formulations. IFT measurements and bulk–foam tests were also conducted to study the salinity–gradient effect on the performance of ultralow–IFT foam. Ultralow–IFT foam–injection strategies were investigated through a series of coreflood experiments in both homogeneous and fractured oil–wet core systems with initial oil/brine two–phase saturation. The representative fractured system included a well–defined fracture by splitting the core sample lengthwise. A controllable initial oil/brine saturation in the matrix can be achieved by closing the fracture with a rubber sheet at high confining pressure. The surfactant formulation achieved ultralow IFT (magnitude of 10−2 to 10−3 mN/m) with the crude oil at the displacement front and good foamability at underoptimal conditions. Both ultralow–IFT and foamability properties were found to be sensitive to the salinity gradient. Ultralow–IFT foam flooding achieved more than 50% incremental oil recovery compared with waterflooding in fractured oil–wet systems because of the selective diversion of ultralow–IFT foam. This effect resulted in a crossflow near the foam front, with surfactant solution (or weak foam) primarily diverted from the fracture into the matrix before the foam front, and oil/high–salinity brine flowing back to the fracture ahead of the front. The crossflow of oil/high–salinity brine from the matrix to the fracture was found to create challenges for foam propagation in the fractured system by forming Winsor II conditions near the foam front and hence killing the existing foam. It is important to note that Winsor II conditions should be avoided in the ultralow–IFT foam process to ensure good foam propagation and high oil–recovery efficiency. Results in this work contributed to demonstrating the technical feasibility of ultralow–IFT foam in high–temperature, ultrahigh–salinity fractured oil–wet carbonate reservoirs and investigated the injection strategy to enhance the low–IFT foam performance. The ultralow–IFT formulation helped to mobilize the residual oil for better displacement efficiency and reduce the unfavorable capillary entry pressure for better sweep efficiency. The selective diversion of foam makes it a good candidate for a mobility–control agent in a fractured system for better sweep efficiency.

Experimental investigation into l-Arg and l-Cys eco-friendly surfactants in enhanced oil recovery by considering IFT reduction and wettability alteration

Surfactant flooding is an important technique used to improve oil recovery from mature oil reservoirs due to minimizing the interfacial tension (IFT) between oil and water and/or altering the rock wettability toward water-wet using various surfactant agents including cationic, anionic, non-ionic, and amphoteric varieties. In this study, two amino-acid based surfactants, named lauroyl arginine (l-Arg) and lauroyl cysteine (l-Cys), were synthesized and used to reduce the IFT of oil–water systems and alter the wettability of carbonate rocks, thus improving oil recovery from oil-wet carbonate reservoirs. The synthesized surfactants were characterized using Fourier transform infrared spectroscopy and nuclear magnetic resonance analyses, and the critical micelle concentration (CMC) of surfactant solutions was determined using conductivity, pH, and turbidity techniques. Experimental results showed that the CMCs of l-Arg and l-Cys solutions were 2000 and 4500 ppm, respectively. It was found that using l-Arg and l-Cys solutions at their CMCs, the IFT and contact angle were reduced from 34.5 to 18.0 and 15.4 mN/m, and from 144° to 78° and 75°, respectively. Thus, the l-Arg and l-Cys solutions enabled approximately 11.9% and 8.9% additional recovery of OOIP (original oil in place). It was identified that both amino-acid surfactants can be used to improve oil recovery due to their desirable effects on the EOR mechanisms at their CMC ranges.

An experimental investigation into enhancing oil recovery using combination of new green surfactant with smart water in oil-wet carbonate reservoir

Enhancing oil recovery from oil-wet carbonate oil reservoir is an important challenge in the world, especially in Middle East oil field. Surfactant and smart water can change the interfacial tension and wettability condition of this type of rock to water wet from oil wet. The present study follows the experimental work of the combination of new green surfactant with smart water to enhance oil recovery from a carbonate oil-wet rock. Wettability alternation and IFT reduction by surfactant, smart water and combination of surfactant with smart water were investigated experimentally. The results show that making surfactant solution using smart water can reduce oil saturation by reducing IFT and alter wettability conditions. The oil recovery factor at the end of water, surfactant and surfactant–smart water flooding was 36, 52 and 66%, respectively. It shows that combination of surfactant with smart water can help surfactant to be powerful.

Ion type adjustment with emphasize on the presence of NaCl existence; measuring interfacial tension, wettability and spreading of crude oil in the carbonate reservoir

Finding the high-performance anions and cations in the aqueous solutions are crucially required during the smart water injection make it the main core of many enhanced oil recovery (EOR) studies. Nevertheless the previously published literature revealed a lack of understanding about the synergistic or antagonistic effect of NaCl (as the most abundant salt in the sea water) and other salts with the same ionic strength on the interfacial tension (IFT), wettability alteration and spreading coefficient. Therefore, the main purpose of this study is aimed on this concern. To reach this goal, the dynamic IFT values of crude oil/different aqueous solutions with ionic strength of 0.7 M and contact angle values between these phases on the oil wet carbonate surface soaked under different times in the prepared aqueous solutions are measured. After that, the measured values are used to calculate the spreading coefficient and distribution capability of oil and water phases on the carbonate rock surface. The obtained results revealed that to change the wetting state of carbonate rock toward a more water wet state, a synergistic effect was observed between NaCl and salts containing sulfate anion, i.e. Na2SO4 and MgSO4.

Role of Brine Composition and Water-Soluble Components of Crude Oil on the Wettability Alteration of a Carbonate Surface

In this study, the effects of amphiphilic water-soluble components of crude oil and ionic composition of water were investigated on the wettability alteration of a carbonate surface. Four different types of saltwater, which are made up of NaCl, MgCl2, CaCl2, and Na2SO4, with 0.5 M ionic strength, besides distilled water, were contacted with crude oil to be saturated with water-soluble components. The post-contact (after contact with crude oil) water properties were characterized by Fourier transform infrared spectroscopy, total organic carbon, and pH analyses. The results showed that some polar compounds of crude oil with basic and mostly acidic functional groups were transferred to saltwater and distilled water. Afterward, the oil-wet carbonate surface was soaked in both freshwater (not contacted with crude oil) and post-contact water, and their effects on the wettability of the surface were investigated through contact angle and scanning electron microscopy experiments. The results of the contact angle ...

Study of surfactant alternating gas injection (SAG) in gas-flooded oil-wet, low permeability carbonate rocks

Many low permeability carbonate reservoirs are gasflooded but leave behind a large amount of residual oil. Surfactant solutions can be injected with gas to improve recovery. Surfactants and gas have the potential to form foam that can improve both oil displacement efficiency and sweep efficiency in oil reservoirs. However, in many carbonate reservoirs, foams need to overcome two adverse conditions: oil-wettability and low permeability. This study investigates the performance of 2 surfactant formulations in gas-flooded low permeability, oil-wet carbonate cores: one that combine wettability alteration, low interfacial tension (IFT), and coarse foaming and the other that is only foaming. Phase behavior experiments were performed to determine the optimal salinity for low oil-water IFT. Contact angle and imbibition experiments were performed on initially oil-wet media to identify surfactants for wettability altering capabilities. Coinjection coreflood experiments of surfactant solution and gas (with no crude oil) were performed at a constant injection rate with varying gas/water ratio and at varying injection rates to determine the critical foam parameters. Finally, oil displacement experiments were performed in low permeability limestone cores using the promising surfactant formulations to study the effect on incremental oil recovery after gas EOR injection process. In addition, dynamic adsorption tests were performed to estimate the adsorption of surfactants in limestone rocks. Mobility reduction factors obtained in coinjection experiments were low (less than 10 in most cases) in tight carbonate cores. The foaming was very coarse or weak, if any. There was a significant hysteresis effect at higher foam injection velocity; the foaming behavior in low permeability carbonate rocks were very weak and very different compared to those in high permeability rocks. Wettability alteration and low IFT can be achieved with anionic surfactants that generate coarse foam and help in fluid diversion. Adsorption of the anionic surfactants studied was between 0.04 and 0.11 mg/gm of rock in presence of alkali and EDTA in tight carbonate formations. Oil displacement experiments in oil-wet carbonate cores revealed that tertiary oil-recovery with injection of wettability-altering, low IFT surfactant can recover a significant amount of oil (about 28–70% ROIP) over the secondary gas flood. The pressure drops in the presence of oil suggested rapid foam coalescence and unstable foam in oil-wet carbonate cores. Good foaming surfactant that does not change wettability or achieve low IFT recovered less oil. Low IFT and wettability alteration in synergy with coarse foaming improves incremental oil recovery significantly and is crucial for higher oil recovery in oil-wet porous media.

Surfactant Prefloods During Carbon Dioxide Foam Injection for Integrated Enhanced Oil Recovery in Fractured Oil-Wet Carbonates

Summary An integrated enhanced-oil-recovery (EOR) (IEOR) approach is used in fractured oil-wet carbonate core plugs where surfactant prefloods reduce interfacial tension (IFT), alter wettability, and establish conditions for capillary continuity to improve tertiary carbon dioxide (CO2) foam injections. Surfactant prefloods can alter the wettability of oil-wet fractures toward neutral/weakly-water-wet conditions that in turn reduce the capillary threshold pressure for foam generation in matrix and create capillary contact between matrix blocks. The capillary connectivity can transmit differential pressure across fractures and increase both mobility control and viscous displacement during CO2-foam injections. Outcrop core plugs were aged to reflect conditions of an ongoing CO2-foam injection field pilot in west Texas. Surfactants were screened for their ability to change the wetting state from oil-wet using the Darcy-scale Amott-Harvey index. A cationic surfactant was the most effective in shifting wettability from an Amott-Harvey index of –0.56 to 0.09. Second waterfloods after surfactant treatments and before tertiary CO2-foam injections recovered an additional 4 to 11% of original oil in place (OIP) (OOIP), verifying the favorable effects of a surfactant preflood to mobilize oil. Tertiary CO2-foam injections revealed the significance of a critical oil-saturation value below which CO2 and surfactant solution were able to enter the oil-wet matrix and generate foam for EOR. The results reveal that a surfactant preflood can reverse the wettability of oil-wet fracture surfaces, lower IFT, and lower capillary threshold pressure to reduce oil saturation to less than a critical value to generate stable CO2 foam.

Wettability modification of oil-wet carbonate reservoirs using silica-based nanofluid: An experimental approach

Wettability is an important factor which controls oil recovery and fluids displacement efficiency in the porous media. Wettability alteration (WA) from strongly oil-wet towards water wet or neutral states is one of the most effective methods of oil recovery increment. Many studies have shown that nanofluid can change the wettability of rock surface towards a desirable state and base on literature structural disjoining pressure is the main mechanism of wettability alteration via nano-treatment. However, there is a lack of information regarding the impact of salinity on nanofluid performance in porous media. Therefore, in this work, the effects of salinity, nanofluid concentration and rock type (i.e. limestone and dolomite surfaces) on wettability alteration of oil wet carbonate substrates under ambient condition were investigated. For this purpose, various static and dynamic experiments including contact angle, imbibition and core flood tests have been performed. The results on contact angle measurements showed that by increasing nanoparticles and electrolyte concentration the wettability alteration from oil wet to water wet was significantly enhanced. Moreover, the wettability alteration of dolomite substrate is much more than that of limestone substrate. In the following, the impact of nanofluid on the spontaneous imbibition for strongly oil-wet carbonate cores was closely examined. Finding results showed an increase as much as 15% of oil recovery for nanofluid imbibition in comparison to that of formation brine. Final evaluation of the nanofluid treatment in terms of its effectiveness was measured by core flood experimental runs. Comparison of relative permeability curves before and after treating have outlined that after the treatment process, the relative permeability curve has shifted to the right and the water relative permeability has reduced from 0.43 mD to 0.23 mD at the residual oil saturation due to wettability alteration of rock surface from strongly oil wet to water wet state.

Foam Generation, Propagation and Stability in Porous Medium

There have been several foam field applications in recent years. Foam treatments targeting gas mobility control in injectors as well as gas blocking in production wells have been performed without causing operational problems. The most widely used injection strategy of foam has been injecting alternating slugs of surfactant in brine with gas injection. This procedure seems to be beneficial as injection is easy to perform and control below fracturing pressure. Simultaneous injection of surfactant solution and gas may give difficulties, especially with interpretation of the tests, if fracturing pressure are exceeded during the injection period. This paper reviews critical aspects of foam for reservoir applications and intends to motivate for further field trials. Key parameters for qualification of foam are: foam generation, propagation in porous medium, foam strength and stability of foam. Stability is discussed, especially in the presence of oil at reservoir conditions. Data on each of these topics are included, as well as extracted summary of relevant literature. Experimental studies have shown that foam is generated at low surfactant concentration even below the CMC (critical micelle concentration). Results indicate that in situ foam generation in porous medium may depend on available nucleation sites. In situ generation of foam is complex and has been found to be especially difficult in oil wet carbonate rocks. Foam propagation in porous medium has been summarized, and propagation rate for a given experiment seems to be constant with time and distance. Laboratory studies confirm a propagation rate of 1–3 m/day. Field tests performed have not given reliable information of foam propagation rate, and future field pilots are encouraged to include observation wells in order to gain information of field-scale foam propagation. Foam strength is generally high with all gases. The exception is CO2 at high pressure where CO2 becomes supercritical. Stability of foam has been studied in laboratory and field tests, and has confirmed long-term stability of foam.

Impact of ionic composition on modulating wetting preference of calcite surface: Implication for chemically tuned water flooding

Despite previous researches on ion-engineered waterflooding (IEWF), its underlying mechanisms are not fully understood, particularly in presence of additives, like surfactants. This paper concerned with the contribution of Ca2+, Mg2+, SO42- and Na+ into altering wettability of oil-wet carbonate minerals towards water preferred state. As a mechanistic study, an experiment workflow was conducted to probe the impact of ions' concentrations in SW, either with or without sodium dodecylbenzene sulfonate (SDBS) which is an anionic surfactant. At first, contact angle (CA) measurement was carried out to evaluate the degree of wettability reversal upon treating the oil-aged calcite slabs with desired ionic composition. Further, to evaluate dynamic response of wettability alteration, the core-flood operation was carried out by successive injection of solutions selected by static CA results.In the case of plain SW flooding, i.e., without surfactant, sulfate dominates success of IEWF, without which wettability reversal did not occur. However, at quadrupled concentration, it acts detrimentally. Ca2+ and Mg2+ both showed an increasing trend of wettability improvement versus concentration. Also, Na+ adversely affected the treating process, without which calcite surface became a neutral state. Oil recoveries observed by core-flood experiment were in accordance with primitive CA measurements. Having SDBS generally improved the wetting reversal, while with a distinct response against salinity. The synergic actions of individual ions and SDBS molecules were interpreted via three interaction modes: surface adsorption of surfactant by increasing Na+, hydrophobic interaction of SDBS's tail with adsorbed carboxylates and releasing those compounds, and reduction of monomeric surfactants by forming strong ion-pairs with divalent cations, particularly Mg2+. The effect of IFT reduction and wettability modification of SDS was distinguished via a special flooding scenario, where latter proved to be significant and kinetically controlled.

Dynamics of Low-Interfacial-Tension Imbibition in Oil-Wet Carbonates

Summary Surfactants induce spontaneous imbibition of water into oil-wet porous media by wettability alteration and interfacial-tension (IFT) reduction. Although the dependence of imbibition on wettability alteration is well-understood, the role of IFT is not as clear. This is partly because, at low IFT values, most water/oil/amphiphile(s) mixtures form emulsions and/or microemulsions, suggesting that the imbibition is accompanied by a phase change, which has been neglected or incorrectly accounted for in previous studies. In this paper, spontaneous displacement of oil from oil-wet porous media by microemulsion-forming surfactants is investigated through simulations and the results are compared with existing experimental data for low-permeability cores with different aspect ratios and permeabilities. Microemulsion viscosity and oil contact angles, with and without surfactant, were measured to better initialize and constrain the simulation model. Results show that with such processes, the imbibition rate and the oil recovery scale differently with core dimensions. Specifically, the rate of imbibition is faster in cores with larger diameter and height, but the recovery factor is smaller when the core aspect ratio deviates considerably from unity. With regard to the mechanism of water uptake, our results suggest, for the first time, that (i) microemulsion formation (i.e., fluid/fluid interface phenomenon) is fast and favored over the wettability alteration (i.e., rock-surface phenomenon) in short times; (ii) a complete wettability transition from an oil-wet to a mixed microemulsion-wet and surfactant-wet state always occurs at ultralow IFT; (iii) wettability alteration causes a more uniform imbibition profile along the core but creates a more diffused imbibition front; and (iv) total emulsification is a strong assumption and fails to describe the dynamics and the scaling of imbibition. Wettability alteration affects the imbibition dynamics locally by changing the composition path, and at a distance by changing the flow behavior. Simulations predict that even though water is not initially present, it forms inside the core. The implications of these results for optimizing the design of low-IFT imbibition are discussed.

Effect of NiO/SiO2 nanofluids on the ultra interfacial tension reduction between heavy oil and aqueous solution and their use for wettability alteration of carbonate rocks

One of the important factors in enhanced oil recovery (EOR), which leads to better oil flow in reservoirs and increases the recovery efficiency of the reservoirs, is the reduction of surface tension (S.T) and interfacial tension (IFT). The effect of NiO and SiO2 nanoparticles and their nanocomposites as NiO/SiO2 on the reduction of oil/water interfacial tension was investigated for the heavy oil of Soroush field located in Iran with a density of 0.965 g/cm3 and viscosity of 1310 cP at 22 °C. NiO and SiO2 nanoparticles were produced by sol-gel-hydrothermal process and NiO/SiO2 nanocomposites were synthesized by co-precipitation-hydrothermal method. The interfacial tension of water/Soroush oil was measured to be 29.02 mN/m, as the reference, in the absence of nanoparticles. Water-based nanofluid of 30 wt% NiO/SiO2 and 28 wt% Fe@ NiO/SiO2 nanocomposites that benefits the synergism of the Fe promotor, decreased the IFT to 1.28 mN/m and less than 1 mN/m, respectively. In addition, the key factors such as concentration, aging time and salinity affect were studied in variation of S.T and IFT. It was found that 8 v/v% of the 30 wt% NiO/SiO2 diluted in water had the best efficiency in reducing the S.T and IFT, while preheating time of nanofluids and salinity of water that the nanofluid dissolved in had negligible impacts on surface and interfacial tension. Moreover, as the 30 wt% NiO/SiO2 nanocomposites were essentially hydrophobic, novel hydrophilic and eco-friendly nanocomposites of 30 wt% NiO/SiO2 were also synthesized through smart surface modifications by polyethylene glycol (PEG 6000) and polydimethylsiloxane. It was shown that the surface-modified nanocomposites could reduce the S.T and IFT significantly and alter the wettability of a strong oil-wet carbonate rock to water-wet condition.