Improved low-salinity waterflooding via a novel nanocomposite for wettability alteration, interfacial tension reduction, and colloidal stability enhancement in porous medium

Low‐salinity surfactant (LSS) flooding is a combined enhanced oil recovery (EOR) technique that increases oil recovery (OR) by altering the rock surface wettability and reducing oil–water interfacial tension (IFT). In this study, optimum concentrations of several types of salt in distilled water were obtained on the basis of IFT experiments for the preparation of low‐salinity water (LSW). Then, a new oil‐based natural surfactant (Gemini surfactant, GS) was combined with LSW to investigate their effects on IFT, wettability, and OR. Experimental results showed that LSW is capable of reducing IFT and contact angle, but the synergy of GS and the active ions Mg2+, Ca2+, and SO42− in LSW was more effective on IFT reduction and wettability alteration. The combination of 1000 ppm MgSO4 and 3000 ppm GS led to a decrease in contact angle from 134.82° to 36.98° (oil‐wet to water‐wet). Based on core flooding tests, LSW injection can increase OR up to 71.46% (for LSW with 1000 ppm MgSO4), while the combination of GS and LSW, as LSS flooding, can improve OR up to 84.23% (for LSS with 1000 ppm MgSO4 and 3000 ppm GS). Therefore GS has great potential to be used as a surfactant for EOR.

Summary Low salinity (LS) water flooding and CO2 flooding are two new combination floods coupled due to the vital role of both in methods for increasing oil recovery. LS water was examined by many laboratory and field works, and it showed an impressive result in enhancing oil recovery. CO2 was tested on increasing oil recovery, and the oil recovery increased by improved wettability alteration effect towards more water-wet and interfacial tension reduction. Although CO2 showed an improvement in oil recovery, the density difference between CO2 and oil resulted in gravity override and channeling problems. LS water alternating CO2 flood gathers the benefits of LS itself to improve sweep efficiency by CO2, prevent the CO2 problems mentioned earlier, and capture the CO2 from the atmosphere. Furthermore, miscible CO2 flooding can reduce oil viscosity and trigger oil swelling. The laboratory experiments of all scenarios showed an incremental oil recovery, but the optimum scenario was the huff and puff-LS water-CO2-LS water scenario with additional oil recovery of 20.65% of OOIP. The three-hours huffing mobilized a new bank of oil, while the shorter LS water-CO2 cycles were the second optimum with incremental oil recovery 17.95% of the OOIP. This combination technology can solve the CO2 flooding problems and support CO2 by LS water, which in itself can increase oil recovery by altering the wettability towards more water-wet.

EDTA chelating agent/seawater solution as enhanced oil recovery fluid for sandstone reservoirs

A new generation improved oil recovery methods comes from combining techniques to make the overall process of oil recovery more efficient. One of the most promising methods is combined Low Salinity Surfactant (LSS) flooding. Low salinity brine injection has proven by numerous laboratory core flood experiments to give a moderate increase in oil recovery. Current research shows that this method may be further enhanced by introduction of surfactants optimized for lowsal environment by reducing the interfacial tension. Researchers have suggested different mechanisms in the literature such as pH variation, fines migration, multi-component ionic exchange, interfacial tension reduction and wettability alteration for improved oil recovery during lowsal injection.In this study, surfactant solubility in lowsal brine was examined by bottle test experiments. A series of core displacement experiments was conducted on nine crude oil aged Berea core plugs that were designed to determine the impact of brine composition, wettability alteration, Low Salinity Water (LSW) and LSS flooding on Enhancing Oil Recovery (EOR). Laboratory core flooding experiments were conducted on the samples in a heating cabinet at 60 °C using five different brine compositions with different concentrations of NaCl, CaCl2 and MgCl2 . The samples were first reached to initial water saturation, S wi , by injecting connate water (high salinity water). LSW injection followed by LSS flooding performed on the samples to obtain the irreducible oil saturation.The results showed a significant potential of oil recovery with maximum additional recovery of 7% Original Oil in Place (OOIP) by injection of LS water (10% LS brine and 90% distilled water) into water-wet cores compared to high salinity waterflooding. It is also concluded that oil recovery increases as wettability changes from water-wet to neutral-wet regardless of the salinity compositions. A reduction in residual oil saturation, S or , by 1.1–4.8% occurred for various brine compositions after LSS flooding in tertiary recovery mode. The absence of clay swelling and fine migration has been confirmed by the stable differential pressure recorded for both LSW and LSS flooding. Aging the samples at high temperature prevented the problem of fines production. Combined LSS flooding resulted in an additional oil recovery of 9.2% OOIP when applied after LSW flooding.Surfactants improved the oil recovery by reducing the oil-water interfacial tension. In addition, lowsal environment decreased the surfactant retention, thus led to successful LSS flooding. The results showed that combined LSS flooding may be one of the most promising methods in EOR. This hybrid improved oil recovery method is economically more attractive and feasible compared to separate low salinity waterflooding or surfactant flooding.

Recently the low salinity water flooding has been introduced as an effective enhanced oil recovery method in sandstone and carbonate reservoirs. The recovery mechanism using low salinity water injection is still debatable. The suggested mechanisms are: wettability alteration, interfacial tension reduction, and rock dissolution. In this paper we will introduce a new chemical EOR method for sandstone and carbonate reservoirs that will give better recovery than the low salinity water injection without treating sea water. The new chemical EOR fluid can be used at low concentrations and can be added to the raw sea water without treatment or softening. Low salinity water was proved to cause damage to the reservoir because of the calcium sulfate scale formation during the flooding process. These chemicals are chelating agents at high pH value such as EDTA and HEDTA. Coreflood experiments and zeta potential measurements were performed using EDTA and HEDA chelating agents added to the sea water and injected into Berea sandstone and Indiana limestone cores of 6 in. length and 1.5 in. diameter. The coreflooding experiments were performed at 100°C and high pressure. The newly introduced EOR method does not cause sulfate precipitation and the core permeability was not affected. The coreflooding effluent was analyzed for cations using the ICP to explain the recovery mechanism. The effect of iron minerals on the rock surface charge will be investigated through the measurements of zeta potential for different rocks containing different iron minerals. The oil recovery increase in both sandstone and carbonate cores was up to 23% of the initial oil in place using the new fluid system. The rock dissolution, interfacial tension (IFT) reduction, and wettability alteration were the recovery mechanism in order. The IFT reduction was due to the high pH of the newly introduced fluid. The existence of iron minerals in sandstone rocks increase the positive values of zeta potential and this will change the rock towards more oil wet. Adding EDTA and HEDTA chelating agents at high pH to the sandstone rocks containing iron changed zeta potential to be negative in which changing the rock towards more water wet.

Low salinity water (LSW) flooding alters rock surface wettability toward more water wetness, and consequently, oil recovery will be increased from a carbonate oil reservoir. Surfactant flooding and polymer flooding enhance oil recovery by oil–water interfacial tension (IFT) reduction and water–oil mobility ratio change, respectively. In this study, a combination of LSW and two non-ionic natural surfactants for enhanced oil recovery was evaluated. Four types of salts (CaCl2, MgCl2, Na2SO4, and MgSO4) at different concentrations in distilled water were used to find optimal LSW based on contact angle (CA) reduction. Two non-ionic natural surfactants (a new natural surfactant from Gemini surfactants (GS) family and Tribulus terrestris surfactant) were applied to obtain their optimum concentration based on IFT reduction. The minimum IFT was achieved in 2000 ppm of GS (4.06 mN/m) and 3000 ppm of TTS (6.21 mN/m). Experimental results showed that the presence of GS in low salinity surfactant solution (1000 ppm of MgSO4 and 2000 ppm GS) is capable to reduce IFT (to 1.02 mN/m) and CA (to 31.25°). Therefore, GS showed good results in IFT improvement and wettability alteration. Finally, the optimal LSS was combined with different concentrations of PHPA polymer and injected into cores. Core flooding results demonstrated 69.7% oil recovery for LSW injection, 82.2% for low salinity GS injection (an increase of 12.5%) and 87.9% for low salinity GS-polymer injection (an increase of 5.7%).

A new generation improved oil recovery methods comes from combining techniques to make the overall process of oil recovery more efficient. One of the most promising methods is combined Low Salinity Surfactant (LSS) flooding. Low salinity brine injection has proven by numerous laboratory core flood experiments to give a moderate increase in oil recovery. Current research shows that this method may be further enhanced by introduction of surfactants optimized for lowsal environment by reducing the interfacial tension. Researchers have suggested different mechanisms in the literature such as pH variation, fines migration, multi-component ionic exchange, interfacial tension reduction and wettability alteration for improved oil recovery during lowsal injection. In this study, surfactant solubility in lowsal brine was examined by bottle test experiments. A series of core displacement experiments was conducted on nine crude oil aged Berea core plugs that were designed to determine the impact of brine composition, wettability alteration, Low Salinity Water (LSW) and LSS flooding on Enhancing Oil Recovery (EOR). Laboratory core flooding experiments were conducted on the samples in a heating cabinet at 60 °C using five different brine compositions with different concentrations of NaCl, CaCl2 and MgCl2. The samples were first reached to initial water saturation, Swi, by injecting connate water (high salinity water). LSW injection followed by LSS flooding performed on the samples to obtain the irreducible oil saturation. The results showed a significant potential of oil recovery with maximum additional recovery of 7% Original Oil in Place (OOIP) by injection of LS water (10% LS brine and 90% distilled water) into water-wet cores compared to high salinity waterflooding. It is also concluded that oil recovery increases as wettability changes from water-wet to neutral-wet regardless of the salinity compositions. A reduction in residual oil saturation, Sor, by 1.1–4.8% occurred for various brine compositions after LSS flooding in tertiary recovery mode. The absence of clay swelling and fine migration has been confirmed by the stable differential pressure recorded for both LSW and LSS flooding. Aging the samples at high temperature prevented the problem of fines production. Combined LSS flooding resulted in an additional oil recovery of 9.2% OOIP when applied after LSW flooding. Surfactants improved the oil recovery by reducing the oil-water interfacial tension. In addition, lowsal environment decreased the surfactant retention, thus led to successful LSS flooding. The results showed that combined LSS flooding may be one of the most promising methods in EOR. This hybrid improved oil recovery method is economically more attractive and feasible compared to separate low salinity waterflooding or surfactant flooding.

Low permeability rock usually holds a large amount of residual oil after flooding. The two most important mechanisms for residual oil recovery are interfacial tension (IFT) reduction and wettability alteration (WA). There is confusion around the coupled effect between the two mechanisms. Permeability is found to be a critical factor on the coupled effect. In this study, the spontaneous imbibition oil recovery results from core plugs of different permeability by using two surfactants were compared. The comparison helps understand the impact of permeability on the coupled effect of IFT reduction and WA. Filtered crude oil (density 0.87 g/mL, viscosity 12.492 cP), Indiana limestone cores of different permeabilities, two locally synthesized cationic gemini surfactants, GS3 and GS6, were used in this study. The spinning drop method and static contact angle method were used to measure the oil/water IFT and the wettability. Spontaneous imbibition experiments using Amott cells were conducted at the ambient condition to relate IFT reduction and WA performance to the oil recovery contribution. Results showed that although the selected surfactants had comparable IFT reduction performance, GS3 is much stronger than GS6 in altering oil-wet carbonate rock to water-wet conditions. In core plugs with the same dimensions and comparable low permeabilities, the oil recovery values accorded with the WA performance. GS3 obtained faster and higher oil recovery (24%) than and GS6 (14%), indicating that enhancing WA alone contributes to oil recovery. The main difference between the selected surfactants was the spacer structure. It appeared that introducing unsaturation into the spacer group harmed the WA performance. Comparing different permeability conditions, GS6 obtained much higher oil recovery in a high permeability condition (922 mD) than in a low permeability condition (7.56 mD). Though permeability significantly impacted the whole imbibition process, it was more auspicious when IFT reduction became the main driving force. This study studied the WA mechanism alone by adopting surfactants with comparable oil/water IFT values. It also features the impact of permeability by comparing the recovery curve by the same surfactant under different permeability, showing that IFT reduction contributes more to oil recovery in high permeability rock.

A study of the performance of the LSWA CO2 EOR technique on improvement of oil recovery in sandstones

ABSTRACTInjection of chemicals in a carbonate reservoir may change wettability and reduce interfacial tension (IFT). The question is how much each mechanism contributes to the increase in oil recovery. There is lack of such information in the literature. The information is very important because it will guide us to select which chemicals to use, as some chemicals can effectively reduce IFT, whereas others can change wettability.This paper aims to compare the effects of different mechanisms in oil recovery related to chemical enhanced oil recovery (EOR) . Particularly, we compare the effects of wettability alteration and IFT reduction. Numerical simulation models are used. Our results show that wettability alteration plays important roles when IFT is high, and it is effective in the early time. IFT plays very important roles with or without wettability alteration and is effective during the entire process. Note that the matrix permeability is reasonably high so that the fluids can be redistributed. The implication is that anionic surfactants are preferred to cationic surfactants in chemical EOR, as the former are generally used to reduce IFT, whereas the latter are used to change wettability. Other observations are that in surfactant‐induced wettability alteration with low IFT, gravity drive is a very important mechanism. Molecular diffusion of chemicals affects oil recovery rate in the early time, but not ultimate oil recovery. © 2012 Curtin University of Technology and John Wiley & Sons, Ltd.

Surfactant oil recovery in fractured carbonates: Experiments and modeling of different matrix dimensions

Mechanistic investigation of using optimum saline water in carbonate reservoirs low asphaltenic crude oil with high resin content: A carbonate-coated microfluidic study

Investigation on the hybrid enhanced oil recovery solutions and methods is gaining attention during the last decade since they can activate multiple mechanisms such as viscosity reduction, interfacial tension (IFT) reduction, and wettability alteration. So, the current work is concentrated on the application of 1-octyl-3-methyl pyridinium chloride ([C8py][Cl]) and 1-dodecyl-3-methyl pyridinium chloride ([C12py][Cl]) as novel surfactants in the absence and presence of SiO2 nanoparticles (SiO2-NPs) for the first time for possible IFT reduction and rock wettability change (contact angle (CA) measurement). In this way, the concentration of ionic liquids (ILs) and SiO2-NPs ranged between 0–2000 ppm and 0–1000 ppm, respectively, to see the influence of these chemicals on the wettability change and IFT reduction. The point is that the higher concentrations of these chemicals were not examined since using higher concentrations makes it expensive and uneconomic for field-scale applications. The obtained results revealed that as the pH increases from 3 to 11 in the absence of different chemicals (formation brine/basic crude oil), the IFT experiences an increase from 20.3 to 31.2 mN/m, while the situation for CA is more complicated. In detail, the results revealed that increasing the pH in the range of 3–11 leads to an increase in the CA from 103.2° to 121.3° (increasing pH from 3 to 7) while a further increase in the pH leads to a reduction in CA value from 121.3° to 118.3°. Moreover, the results revealed that increasing the concentration of [C8py][Cl] from 0 to 2000 ppm led to a reduction in IFT value from 20.3 to 0.95 mN/m for pH of 3, from 27.3 to 2.2 mN/m for pH of 7 and from 31.2 to 5.4 mN/m for pH of 11. Besides, the measurements for [C12py][Cl] revealed that increasing the concentration from 0 to 2000 ppm leads to IFT reduction from 20.3 to 0.74 mN/m for pH of 3, from 27.3 to 0.9 for pH of 7, and from 31.2 to 1.4 mN/m for pH of 11. The results demonstrated a higher influence of [C12py][Cl] on the IFT reduction compared with the [C8py][Cl] due to the longer alkyl chain length of [C12py][Cl] which means more detergency power. Furthermore, the effects of these two ILs are examined on the wettability change which showed that both of the examined ILs are capable to manipulate the wettability of the rock surface toward water-wet conditions (53.3°) from oil-wet conditions (121.3°). Also, the influence of SiO2-NPs in the range of 0–1000 ppm is investigated on the IFT reduction and wettability change while the concentration of ILs is held constant at 2000 ppm since the concentration of 2000 ppm leading to the lowest CA and IFT values for both examined ILs. The obtained results reveal that not only the presence of SiO2-NPs with a maximum concentration of 1000 ppm leads to a reducing trend on the IFT in particular for the pH of 11 regardless of the used IL but also it changes the surface wettability to strongly water-wet condition with minimum CA value of 28.5°. In the last stage, the efficiency of the optimum chemical formulations was examined through core flooding experiments using conventional core flooding procedure and the core flooding experiments concomitant with the soaking time (30 days). The experiments revealed that the chemical formulation under a pH of 3 leads to the highest oil recovery factors while the lowest oil recovery factors are obtained under a pH of 11. Besides, the core flooding experiments followed by soaking reveal the ultimate oil recovery of 10.1 and 13.3% based on the original oil in place (OOIP) due to better activation of the wettability change mechanism which was 46% higher than the situation no soaking was performed. The findings of this study can help for a better understanding of the feasibility and applicability of using new hybrid surfactant-NPs-based EOR methods to activate wettability alteration and IFT reduction, especially with a main focus on one specific fraction of crude oil (resin fraction) instead of crude oil.

Enhanced Oil Recovery (EOR) methods using injection of cost-effective, water-soluble chemical additives (e.g., surfactants and mutual solvents) have great potential for increasing oil recovery from low-permeability fractured reservoirs. In a previous paper (Alghunaim et al., 2021), we presented experimental results pertaining to the efficacy of using a 1% solution of 3-pentanone (a mutual solvent) and separately a 1% non-ionic surfactant solution injected in four unfractured Permian Basin carbonate cores saturated with a low-salinity brine. The experiments indicated that we produced substantial amounts of oil from the four non-fractured Permian Basin San-Andres cores with permeability ranging from 2.67 mD to 17 mD, and porosity from 7.4% to 12.14%. In the experimental study pertaining to this paper, we used a fractured and an unfractured sandstone core to demonstrate oil recovery potential of 3-pentanone. The main factors that affect oil recovery from fractured reservoirs are preferential flow through fractures that provide large surface areas, matrix rock heterogeneity, and rock wettability. The wettability modifying agents reduce both the interfacial tension between oil and water and the water-oil contact angle to enhance oil recovery. The laboratory assessment included measurements of interfacial tension, rock wettability alteration, and incremental oil recovery beyond waterflood. To quantify the efficacy of 3-pentanone, coreflooding experiments included injecting this mutual solvent both in an unfractured core and a fractured core in a Colton sandstone from Central Utah. The effects of changing concentration of 3-pentanone and duration of soaking period before injecting water were also investigated. The results showed that the oil recoveries from the unfractured core and fractured core at the end of the flooding tests were 59.85% and 64.28%, respectively with the incremental oil recovery of 7% and 22%, respectively. The incremental oil recovery from 3-Pentanone can be explained by the combination of various mechanisms that includes a slight reduction in interfacial tension, alteration of rock wettability from water-wet to strongly water-wet (contact angle reduced from 38° to 18°) and ketone partitioning into the oil phase with a reduction in oil viscosity and increased oil mobility. The increase in enhanced oil recovery by ketone solution in the fractured core is probably due to the increase in mass transfer surface area between the fracture and the rock matrix. The 3-pentanone solution provides an operationally simple, environmentally friendly, and cost-effective EOR method in low-permeability formations.

Improving oil recovery from unconventional liquid reservoirs (ULR) is a major challenge. We have demonstrated in previous laboratory studies the impact of surfactants on spontaneous imbibition and oil recovery by means of wettability alteration and interfacial tension (IFT) reduction. Thereby, fracture treatment performance and consequently oil recovery could be improved by adding surfactants to stimulation fluids when a soaking-flowback production schedule is applied. This study evaluates the ability of different groups of surfactants to improve oil recovery in ULR by experimentally simulating the fracture-treatment to represent surfactant imbibition in an ULR core-fracture during a soaking-flowback. Also, we analyze the effect of wettability and IFT alteration on the process. A core-flooding system was combined with the computer tomography (CT) scanner to dynamically visualize the fluid movement as it penetrates the ULR sample in real-time as well as compare oil recovery between surfactants and water without additive. Wolfcamp sidewall cores were longitudinally fractured and loaded into an aluminum-carbon composite core-holder. Two different types of surfactants, anionic and nonionic-cationic, as well as water without surfactants, were injected through the fractures, at reservoir conditions, to evaluate their effectiveness in penetrating into the fractures and recovering oil from ULR core. Then, a soaking-flowback production scheme was used to simulate fracture-treatment and flowback. Changes in core wettability and IFT were determined by contact-angle and pendant-drop methods. Core-flooding results showed that surfactant solutions had higher imbibition and recovered more oil from liquid-rich core compared to water alone. The soaking-flowback production schedule aided by surfactants was able to recover up to 14% of the original oil in place (OOIP) whereas water alone recovered up to 2% of the OOIP. These observations qualitatively agree with wettability and IFT alteration measurements. Core wettability shifted from an original oil-wet to a final water-wet state and surfactants reduced IFT to moderately low values. The results showed that the addition of surfactants to completion fluids and the use of a soaking-flowback production scheme could improve oil recovery by wettability alteration and IFT reduction, maximizing well performance after stimulation. These findings give important understanding for designing completion fluid treatments and flowback schedules for ULR.