Low Salinity Surfactant Flooding Research Articles

Pore-Scale Investigation of Low-Salinity Nanofluids on Wetting Properties of Oil Carbonate Reservoir Rocks Studied by X-ray Micro-Tomography

Low-salinity surfactant nanofluids have recently shown promising results in the wettability alteration of reservoir rocks from oil-wet state towards more water-wet state. However, the investigation of pore-level interactions of nanofluids injection in real oil carbonate rocks at reservoir conditions, which determines the overall fluid dynamics, is lacking. Therefore, in this work, we studied the effect of nanoparticles augmented low-salinity surfactant flooding on the wettability alteration of hydrophobic carbonate rocks with harsh reservoir conditions via X-ray micro-tomography. The designed experiment scheme involved core flooding with an X-ray transparent core-holder developed for studying the flow properties of fluids at the micro level (pore scale). The wettability was quantified by measuring the differences in contact angles after the injection of low salinity, low-salinity surfactant, and low-salinity surfactant nanofluid. The findings illustrate that surfactant flooding with silica nanoparticles had a more pronounced influence on the contact angle among other injected fluids. The contact angle of the rock fell from 144° to 49°, corresponding to the water-wet conditions of carbonate rocks. The results show that the addition of a low concentration (0.005 wt.%) of SiO2 nanoparticles was enough for wettability changes in oil carbonate rocks. This study illustrates that a combination of surfactant, low-salinity, and nanoparticle features has a more pronounced effect on the three-phase contact angle than if applied separately.

English

Oil reserves in the Niger Delta have been gradually decreasing due to the increased production. New large field discoveries are scarce, thus there is need to improve on the production from existing reserves. Low salinity surfactant flooding (LSSF) is a potential enhanced oil recovery process to increase oil production in the Niger Delta oil fields. In this study, sodium dodecyl sulphate and ethanol were used as surfactant to study the significance of the surfactants on oil recovery. Sand packs were used as formation sample in the laboratory. This was soaked with oil of 24.36° API and specific gravity of 0.9436. Low salinity water was used as a displacing fluid in the secondary recovery mechanism. However, sodium dodecyl sulphate and ethanol (78% vol.) was introduced into the sand packs. The sodium dodecyl sulphate reduced the interfacial tension as obtained using tensiometer machine. Ethanol was used in the second case as surfactant.  The result of the work shows that sodium dodecyl sulphate had oil recovery of 16.1, 16.9, 19.0 and 19.3% respectively at different surfactant concentrations 0.2, 0.3, 0.35and 0.38% wt. respectively; while ethanol (78% vol.) had oil recovery of 1.5%. The study noted that sodium dodecyl sulphate is a good surfactant for enhanced oil recovery for crude oil with the specified API gravity. In addition, interfacial tension reduction and change in rock wettability were the working mechanisms for the sodium dodecyl sulphate to increases oil recovery from reservoirs. The work showed that sodium dodecyl sulphate maintained low interfacial tension through the flood process. Key word: Sodium dodecyl sulphate, interfacial tension reduction, ethanol, crude oil

Capillary desaturation curve: does low salinity surfactant flooding significantly reduce the residual oil saturation?

Different oil displacement experiments conducted on sandstone and carbonate samples show that low salinity water (LSW) injection can reduce the residual oil saturation (ROS). Recently, surfactant flooding (SF) in combination with low salinity water (known as low salinity surfactant (LSS) flooding) is proposed as a potentially promising hybrid enhanced oil recovery (EOR) process. A lower ROS is reported for a LSS process compared to that seen in SF or with LSW at the same capillary number. The capillary desaturation curve (CDC) is a well-known tool to study the effect of viscous and capillary forces on ROS for different EOR techniques. In this study, ROS data of various LSW, SF, and LSS flooding experiments at different capillary numbers are collected to develop a CDC to analyze the performance of the hybrid LSS method. This can help to analyze the effect of the hybrid method on an extra improvement in sweep efficiency and reduction in residual oil. A lower ROS is observed for LSS compared to LSW and SF in the same capillary number range. Our study shows different behaviors of the hybrid method at different ranges of capillary numbers. Three regions are identified based on the capillary number values. The difference in ROS is not significant in the first region (capillary number in the range of 10−7–10−5), which is not applicable in the presence of surfactant due to the low interfacial tension value. A significant reduction in ROS is observed in the second region (capillary number in the range of 10−5–10−2) for LSS compared to SF. This region is the most practical range for SF and LSS flooding. Hence, the application of LSS provides a noticeable benefit compared to normal EOR techniques. In the third region (capillary numbers greater than 10−2), where the surfactant flooding is a better performer, the difference in ROS is negligible.

Experimental study of combined low salinity and surfactant flooding effect on oil recovery

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.

A mechanistic experimental study on the combined effect of Mg2+, Ca2+, and SO42- ions and a cationic surfactant in improving the surface properties of oil/water/rock system

More than half of the discovered hydrocarbon reservoirs in the world are the oil-wet carbonates. Enhanced oil recovery (EOR) from these reservoirs is challenging because of their tendency to retain oil at the rock surface. The use of low salinity (LS) water injection to recover more oil from these types of oil reservoirs has been recommended by several researchers. There are possible mechanisms concerning LS water flooding that have been introduced in the literature; a distinct lack of experimental investigation to enhancing the efficiency of this method is still felt. In this work, a detailed and comprehensive study was carried out on using LS + surfactant (LSS) to improve the surface and interface properties of oil + water + calcite rock samples. In the first step, the point of zero charge of the rock sample was determined. Then, the effect of different salts including MgCl2, CaCl2, and Na2SO4 at different concentrations on improving the oil-water interfacial tension and wettability alteration of the rock surfaces was investigated in the presence and absence of a cationic surfactant, cetyl methylammonium bromide (CTAB), in the operational range of pH. Emulsion formation and adsorption measurement tests were performed for a deep investigation of the performance of the cationic surfactant in the presence of different salts. Finally, waterflooding experiments were carried out and the water/oil relative permeabilities, amount of recovery and wettability alteration were thoroughly investigated for three different injection scenarios.The results showed that the co-presence of magnesium, calcium and sulfate ions all in the presence and absence of CTAB surfactant causes a significant reduction in IFT and contact angle values, especially at the lower ranges of salinity. The addition of divalent cations, i.e., Mg2+ and Ca2+, could reduce the amount of surfactant adsorbed on the calcite rock surfaces, especially in the low ranges of salinities. Also, in flooding tests, an increase in differential pressure between the inlet and outlet faces of the core samples from about 2.9 MPa for LS to about 4.7 MPa for LSS flooding, at the breakthrough time, was observed which was related to the formation of water in oil emulsions during LSS flooding. Comparison of the ratio of the residual to initial oil saturation (Sor/Soi) for different flooding scenarios (i.e., injection of saline water (SW), LS and LSS solutions) indicates that as the salinity of water reduces, the efficiency of CTAB surfactant in improving oil recovery increases.

AI based mechanistic modeling and probabilistic forecasting of hybrid low salinity chemical flooding

Over the past decades, it has been widely shown that Low Salinity Waterflooding (LSW) outperformed High Salinity Waterflooding (HSW) in terms of higher oil recovery, particularly in combining with other conventional Enhanced Oil Recovery (EOR) methods such as chemical flooding to benefit from their synergies. This paper presents a novel approach to mechanistically model Hybrid Low Salinity Chemical Flooding, with: (1) development of a hybrid EOR concept from past decades; (2) utilizing a Multilayer Neural Network (ML-NN) artificial intelligent technique in a robust Equation-of-State reservoir simulator fully coupled with geochemistry; (3) systematic validation with laboratory data; and (4) uncertainty assessment of the LSW process at the field scale.Various parameters such as polymer, surfactant, and salinity can affect on the relative permeability simultaneously during hybrid recovery processes. To overcome this problem, the ML-NN technique was applied for multidimensional interpolation of the relative permeability. Additionally, ML-NN was used within a Bayesian workflow to capture the uncertainties in both history matching and forecasting stages of LSW at field scale. The proposed model indicated good agreements with various coreflooding experiments including HSW, LSW, and Low Salinity Surfactant flooding (LSS), where it can efficiently capture the complex geochemistry, wettability alteration, microemulsion phase behavior, and the synergies occurring in these hybrid processes.

Wettability alteration in carbonate and sandstone rocks due to low salinity surfactant flooding

Commonly, desorption of crude oil from rock surfaces accomplished by the exposure to the decreasing salt concentrations of NaCl, Na2SO4, MgCl2 and CaCl2 solutions. However, adsorption and desorption of crude oil are the functions of several attributing factors at undoubtedly low salinity brine solutions. For silica surfaces, both rock and oil possess negative charges during low salinity injection that leads to the electrical double layer expansion and electrostatic repulsion between them. For carbonate rocks, rock dissolution and negatively charged surface at higher pH could be regarded as the driving forces for oil desorption. Thus, adsorption/desorption studies of different oils over silica and carbonate rocks while considering salinity, ion composition and aging of the rocks would be sufficient to alter the wettability of the rocks. In the present paper, the effect of saline water containing surfactant has been discussed on the performance of enhanced oil recovery (EOR). Wettability alteration triggered by the change in interfacial tension (IFT) between crude oil and low salinity surfactant (LSS) is known to be the main factor regarding EOR processes. However, wettability depends on several factors, namely, multiple ion exchange (MIE), interfacial elasticity modulus, cation bridging, acid/base numbers of oil, rock composition and structure, ratio of divalent/monovalent (M2+/M+) cations in the formation brine, aging time, the status of zeta potential, surfactant structure and concentration, pH of the medium, T & P of reservoir, permeability and pressure drop change. Therefore, we thoroughly examine the microscopic mechanisms of LSS flooding via studying individual aforementioned factors that influence the contact angle change in sandstone and carbonate rocks.

Brine Ions and Mechanism of Low Salinity Water Injection in Enhanced Oil Recovery: A Review

Brine ion improvement and optimization in water flooding is one of the topics which have attracted many researchers in the recent years. Numerous studies have identified Crude Oil/Brine/Rock (COBR) interactions as the main factor contributing to oil recovery factor in both sandstone and carbonate rocks. The current study is a review on previous researches on brine ions and mechanism of Low Salinity Water Injection (LSWI) in Enhanced Oil Recovery (EOR). Results of this literature show that Low Salinity Surfactant Flooding (LSSF) can be introduced as the inter medium method between LSW and surfactant flooding, which includes both of their late benefits (wettability alteration and interfacial tension reduction) simultaneously. Moreover application of software as powerful tools for both simulation and optimization as new cost effective and precise utilization methods have been looked at. In regard with the latest argument two software are introduced; Design of Experiment (DOE) programs which dedicate to LSWI studies as a core medium to simulate LSWI experiments and on the other hand simulation programs to identify the corresponding COBR interactions while LSWI using new software such as UTCHEM software. According to combined results from UTCHEM and experimental tests the main mechanism behind LSWI is wettability alteration to identifying contributors of which special attention is required to determine the main factors involved in, which requires more detailed researches as the actual attributors are not yet known.

A State-of-the-Art Review To Develop Injection-Water-Chemistry Requirement Guidelines for IOR/EOR Projects

SummaryInjection-water chemistry plays a significant role in the impact of several improved-oil-recovery (IOR) and enhanced-oil-recovery (EOR) processes. Recently, advanced waterfloods through the tailoring of injection-water salinity and composition have received good attention in the oil industry for both sandstone and carbonate reservoirs. However, the importance of injection-water chemistry has not received its due attention as a whole in the IOR/EOR business because published studies in this area are distributed sparsely in bits and pieces without much relation to establish the strong connection. Also, injection-water-chemistry effects in certain EOR areas remain largely unexplored, even though they look somewhat promising. Moreover, the existing literature lacks a clear definition of injection-water-chemistry requirement guidelines for all IOR/EOR processes, including some of the newer processes that currently either are being practiced or are in research. In this paper, we provide a comprehensive review of more than 100 papers published during the past several decades in this subject area. The objectives of this review study are to provide an overview of smart-waterflooding technology; to describe important roles played by injection-water chemistry in the IOR/EOR business, with supporting examples; to extend the applicability of the smart-water concept to different IOR/EOR processes; and to develop the desired injection-water-chemistry requirement guidelines for IOR/EOR.The review analyses presented in this paper indicate that injection-water chemistry is important everywhere in the IOR/EOR business and is applicable not only to advanced waterfloods, but also to most of the recovery processes among the three major EOR types. These EOR processes include polymer flooding, alkaline-surfactant-polymer flooding, low-salinity surfactant flooding for sandstones, dilute-surfactant flooding for carbonates, carbonated waterflooding, miscible carbon dioxide (CO2) water-alternating-gas (WAG) flooding, and steamflooding. Injection waters of optimized salinity and ionic composition can also combine synergistically with several other EOR processes to result in higher incremental oil recoveries. Lower-salinity waters have a beneficial effect in polymer, surfactant, dilute-surfactant, and carbonated waterfloods, to yield better oil recoveries when compared with high-salinity water. The use of smart water for tertiary miscible CO2 WAG floods and carbonated waterflooding appears promising; however, it requires additional research to clearly distinguish and determine smart-water effects in these processes. The review analyses are finally extended to develop the desired injection-water-chemistry requirements for all individual IOR/EOR processes currently known. The findings of this study also put forward two major recommendations for consideration by the industry: (1) there is a need for close collaboration between water and oil industries to develop fit-for-purpose water-treatment solutions for addressing IOR/EOR injection-water-chemistry requirements, and (2) some thought should be given to develop “water chemistry” as a specialty discipline within the oil industry, for better integration of this emerging focus area with other key surface- and subsurface-related disciplines to effectively improve upon the IOR/EOR upstream value chain.

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.

Effect of crude oil ageing on low salinity and low salinity surfactant flooding

Injection of brine with lower salinity than the connate brine has proven to give a moderate increase in oil recovery in sandstones. Recent research has shown that this process will significantly benefit from introducing surfactant optimised for low salinity environment. The mechanisms underlying increased recovery by low salinity brine injection are not yet fully understood. However, research to date suggests that they are related to complex crude oil/brine/rock interactions. With this in mind, the present paper investigates primarily how the extent of oil recovery from Berea sandstones subjected to long term exposure of crude oil is influenced by (1) low salinity water injection and (2) combined process low salinity water injection with surfactant flooding. Core displacement tests were conducted on four Berea cores (30 cm), two in a natural state and two that had been subject to extensive crude oil ageing at high temperature. Results obtained from different flooding steps are discussed in terms of oil recovery and effluent properties including turbidity, pH- and ion analysis (Na +, Mg 2+, Ca 2+). The results effectively illustrate that oil recoveries from the aged cores are higher during both low salinity water injection and low salinity water injection combined with surfactant flooding. An assessment of how tertiary oil recovery in aged and unaged cores varies with surfactant concentration is also presented. Effluent ion analysis from low salinity water floods showed that Mg 2+ ions were strongly retained in the aged core while Ca 2+ ions were being produced from both aged and unaged cores. The latter was attributed mainly to calcite dissolution. Results obtained from pressure profiles, effluent ion analysis and turbidity tests suggest higher production and elution of fine particles from the unaged core.