Low Salinity Effects Research Articles

Investigating the low salinity effect in a sandstone reservoir through electro-kinetic potential analysis

This study employs electro-kinetic potential measurements to predict the low salinity effect in a sandstone reservoir. Through comprehensive investigations utilizing Zeta potential, interfacial tension, FTIR spectroscopy, and contact angle measurements, valuable insights were obtained. Positive zeta potentials for Ethanoic-dodecane oil (+9.34) and Crude oil (+14.31), along with decreasing zeta potential values with decreasing NaCl and CaCl2 concentrations, indicated core aging and the adsorption of organic compounds. Wettability alteration and reduced contact angles further confirmed aging-induced changes. Negative Oil/Brine Zeta potentials and trends in interfacial tension supported the presence of the low salinity effect. This study enhances our understanding of low salinity effects in sandstone reservoirs by characterizing electro-kinetic potentials, wettability alterations, and interfacial tensions. It highlights the potential of electro-kinetic potential measurements as a predictive tool for evaluating the low salinity effect, enabling a more comprehensive assessment of its impact on reservoir performance.

A mechanistic study of low salinity water-based nanoparticle-polymer complex fluid for improved oil recovery in sandstone reservoirs

Low salinity water flooding has gained tremendous attention in these days due to its cost-effectiveness and environment-friendly nature. Fine tuning of physico-chemical properties of low saline water by addition of suitable chemicals and nanoparticle (NP) can increase the oil recovery significantly because of synergistic effects. In this study, an attempt has been made to explore the benefit of adding nanoparticle and polymer into low salinity water (LSW) for increased oil recovery. Two complex chemical slugs were prepared with formation water (FW) and LSW as base fluids consisting of different concentrations of polymer and NP. The target viscosity for maximum sweep efficiency was estimated through the total minimum relative mobility concept. The rheological studies of the complex chemical slugs revealed that the addition of NP into polymer solution increased the viscosity significantly because of formation of macromolecular structure. It has been observed that a lower concentration of polymer is required to reach the target viscosity in LSW than FW. The benefits of low salinity effects over high saline formation water are evidenced by the reduction of interfacial tension (IFT), which is further reduced by addition of NP. A low IFT is always desirable for enhanced oil recovery. Contact angle showed a decreasing trend with FW, LSW and Nano fluid solutions respectively but presence of polymer in the slugs shows reverse effect on contact angle. LSW showed higher recovery as compared to FW in secondary recovery stage due to different reported mechanisms. Injection of LSW based complex fluid showed incremental recovery of 13.3 % of OOIP as compared to LSW and 22.0 % of OOIP as compared to conventional FW flooding in secondary stage. Synergistic effect of NP and polymer to form a complex macromolecular structure through hydrogen bonding and low salinity effect led to the improved oil recovery.”

Microfluidics-Based Low Salinity Wettability Alteration Study of Naphthenic-Acid-Adsorbed Calcite Surfaces

Microfluidics is relatively a new area in the oil and gas industry and has great potential to be used as an effective tool to address various outstanding research questions where microscale investigation is necessary. Low salinity brine flooding has been known to enhance oil recovery in carbonate reservoirs through a wettability alteration mechanism. Wettability alteration is a molecular-scale phenomenon that is often characterized at a mesoscale through contact angle experiments. By using microfluidic chips, the low salinity effects involving solid–fluid interactions could be directly visualized, and the wettability alteration could be verified at microscale. However, to replicate solid–fluid interactions involved in carbonate reservoirs, the internal wetting surfaces must be transformed to carbonate surfaces. In this study, first, wetting surfaces of straight-channel glass microfluidic chips were functionalized using a metal-chelating silane coupling agent, and then, the surfaces were coated with CaCO3 using a layer-by-layer (LbL) deposition process. The calcite-coated straight-channel glass microfluidic chips were then used to investigate the effects of brine salinity and the role of divalent ions in the wettability alteration of oil-wet calcite surfaces at both room temperature and high temperature (70 °C). Naphthenic acid was used as the surface-active component in a model oil to render calcite surfaces oil wet. Six single-electrolyte-based brines were used in this study: high salinity 5 M NaCl, seawater equivalent 0.656 M NaCl, and 4-times diluted seawater-equivalent low salinity brines─0.164 M ionic strength NaCl, Na2SO4, MgSO4, and MgCl2. The low salinity brines were found to induce significant wettability alteration on naphthenic-acid-adsorbed calcite surfaces at ambient temperature. Low salinity Na2SO4 resulted in the highest wettability alteration followed by low salinity NaCl solution. Insignificant wettability alteration was observed in 0.656 M NaCl compared to 0.164 M NaCl where the wettability alteration was significant, suggesting the extent of wettability alteration increases with reduction in brine salinity. Magnesium ions were found to be unfavorable for wettability alteration in the presence or absence of sulfate ions. Exposure to higher temperature resulted in no or insignificant further wettability alteration in most of the brines.

An Experimental Study of Improving Viscous Oil Recovery by Using Hybrid Enhanced Oil Recovery Techniques: A Case Study of Alaska North Slope Reservoir

Summary Shallow reservoirs on the Alaska North Slope (ANS), such as Ugnu and West Sak-Schrader Bluff, hold approximately 12 to 17 × 109 barrels of viscous oil. Because of the proximity of these reservoirs to the permafrost, feasible nonthermal enhanced oil recovery (EOR) methods are highly needed to exploit these oil resources. This study proposes three hybrid nonthermal EOR techniques, including high-salinity water (HSW) injection sequentially followed by low-salinity water (LSW) and low-salinity polymer (LSP) flooding (HSW-LSW-LSP), solvent-alternating-LSW flooding, and solvent-alternating-LSP flooding, to recover ANS viscous oils. The oil recovery performance of these hybrid EOR techniques has been evaluated by conducting coreflooding experiments. Additionally, constant composition expansion (CCE) tests, ζ potential determinations, and interfacial tension (IFT) measurements have been conducted to reveal the EOR mechanisms of the three proposed hybrid EOR techniques. Coreflooding experiments and IFT measurements have been conducted at reservoir conditions of 1,500 psi and 85°F, while CCE tests have been carried out at a reservoir temperature of 85°F. ζ potential determinations have been conducted at 14.7 psi and 77°F. The coreflooding experiment results have demonstrated that all of the three proposed hybrid EOR techniques could result in much better performance in reducing residual oil saturation than waterflooding and continuous solvent flooding in viscous oil reservoirs on ANS, implying better oil recovery potential. In particular, severe formation damage or blockage at the production end occurred when natural sand was used to prepare the sandpack column, indicating that the natural sand may have introduced some unknown constituents that may react with the injected solvent and polymer, resulting in a severe blocking issue. Our investigation on this is ongoing, and more detailed studies are being conducted in our laboratory. The CCE test results demonstrate that more solvent could be dissolved into the tested viscous oil with increasing pressure, simultaneously resulting in more oil swelling and viscosity reduction. At the desired reservoir conditions of 1,500 psi and 85°F, as much as 60 mol% of solvent could be dissolved into the ANS viscous oil, resulting in more than 31% oil swelling and 97% oil viscosity reduction. Thus, the obvious oil swelling and significant viscosity reduction resulting from solvent injection could lead to much better microscopic displacement efficiency during the solvent flooding. The ζ potential determination results illustrate that LSW resulted in more negative ζ potential than HSW on the interface between sand and water, indicating that lowering the salinity of injected brine could result in the sand surface being more water-wet, but adding polymer to the LSW could not further enhance the water wetness. The IFT measurement results show that the IFT between the tested ANS viscous oil and LSW is higher than that between the tested viscous oil and HSW, which conflicts with the commonly recognized IFT reduction effect by LSW flooding. Thus, the EOR theory of the LSW flooding in our proposed hybrid techniques may be attributed to low-salinity effects (LSEs) such as multi-ion exchange, expansion of electrical double layer, and salting-in effect, while water wetness enhancement may benefit the LSW flooding process to some extent. The LSP’s viscosity is much higher than the viscosities of LSW and solvent, so LSP injection could result in better mobility control in the tested viscous oil reservoirs, leading to improvement of macroscopic sweep efficiency. Combining these EOR theories, the proposed hybrid EOR techniques have the potential to significantly increase oil recovery in viscous oil reservoirs on ANS by maximizing the overall displacement efficiency.

Changes of Heart Rate and Lipid Composition in Mytilus Edulis and Modiolus Modiolus Caused by Crude Oil Pollution and Low Salinity Effects.

Blue mussels, Mytilus edulis, inhabiting tidal zones, are naturally exposed to fluctuating environmental conditions (e.g., fluctuations in temperature and salinities), while horse mussels, Modiolus modiolus, live under relatively invariable shelf water conditions. The present investigation tested the hypothesis: blue mussels, in comparison to horse mussels, have an increased ability to tolerate the stress of pollution combined with low salinity. To assess the response of blue mussels and horse mussels to oil pollution at seawater salinities of 25 psu (normal) and 15 psu (low), we used a combination of heart rate and lipid composition as physiological and biochemical indicators, respectively. A sharp decrease in heart rate as well as important fluctuations in cardiac activity was observed under all oil concentrations. Modifications in the concentrations of the main membrane lipid classes (phosphatidylcholine, phosphatidylethanolamine, and cholesterol) and storage lipids (primarily triacylglycerols) in response to different crude oil concentrations were time- and dose-dependent. Both chosen indicators showed a high sensitivity to crude oil contamination. Furthermore, both bivalve species showed similar responses to oil pollution, suggesting a universal mechanism for biochemical adaptation to crude oil pollution.

Explicit continuum scale modeling of low-salinity mechanisms

Understanding the influence of injection water composition on the displacement efficiency has been a long-standing issue in reservoir engineering; a reduction of the injection water salinity can lead to additional oil production, which is considered a low-cost and environmentally friendly method for enhanced oil recovery. Several underlying chemical mechanisms have been identified; however, the identification of the governing mechanisms remains difficult and specific to the chemical setting of the reservoir and injection water composition. In this work, we implement two potential mechanisms, namely, double layer expansion and multicomponent ion exchange, to achieve an explicit description of low-salinity effects in the open-source continuum-scale flow simulator DuMuX, with the goal of designing and interpreting experiments, and upscaling the results. By assuming sets of input parameters, we show that there is a minimum required core length dependent on the dispersion of the chemical flooding front dominated by sample heterogeneity. Above this length scale, the saturation profile is fully developed, and the chemical effluent analysis is conclusive, which both is required to calibrate continuum scale models. The change in the chemical water composition shows a characteristic fingerprint for both investigated mechanisms and therefore allows the identification of the leading low-salinity mechanism. The model is publicly available.

The Influence of Rock Composition and pH on Reservoir Wettability for Low-Salinity Water-CO2 Enhanced Oil Recovery Applications in Brazilian Reservoirs

SummaryLow-salinity waterflooding and carbon dioxide (CO2) injection are enhanced oil recovery (EOR) methods that are currently increasing in use worldwide. Linking these two EOR methods is a promising approach in the exploration of mature fields and for post- and presalt basins in Brazil. Moreover, the latter reservoirs already exhibit a high CO2 content by nature. Interfacial phenomena between fluids and rock in a low-salinity water-CO2 (LSW-CO2) environment remain unclear, particularly the wettability behavior that is related to the pH of the medium, among others. This study investigates the influence of rock composition and pH of the brine on reservoir wettability through coreflooding and zeta potential experiments in LSW and determination of contact angles and interfacial tension (IFT) in the crude oil-LSW-CO2 system at reservoir conditions. Brazilian light crude oil, pure CO2, and brine solutions of different concentrations and compositions were used to represent the fluids in actual oil reservoirs. The experiments were carried out on Botucatu sandstone, Indiana limestone, and calcite crystal samples, with mineralogy determined by energy dispersive X-ray (EDX) analysis. Coreflooding experiments were conducted by the injection of 10 pore volumes (PVs) of fourfold diluted synthetic reservoir brine (SRB), followed by 10 PVs of 40-fold diluted SRB to evaluate the low-salinity effects. Interfacial properties, such as contact angle and IFT, as well as density and pH, were determined at elevated pressures to evaluate the synergistic effects between CO2 and salt content. In addition, geochemical modeling using PH REdox EQuilibrium (in C language) (PHREEQC) was performed to predict the in-situ pH and match with the experimental data. An increase in oil recovery and pH of the effluent was observed in the coreflooding experiments during diluted SRB injection. The ionic concentrations of the effluent samples also indicated illite dissolution. Furthermore, zeta potential measurements confirmed the expansion of the water film and shift from positive to negative surface charge of Botucatu sandstone for salt concentrations less than 80,000 mg/L at pH > 7, whereas in Indiana limestone, negative surface charge was only observed in deionized water at pH > 9. These observations indicate that during LSW injection alone, an increase in pH will favor a thicker water layer on the Botucatu sandstone surface that in turn increases water wettability and results in increased oil recovery. Conversely, the presence of CO2 in LSW causes a decrease in the pH of the medium, which is related to further enhancing water wettability when linking pH with contact angle measurements. It seems that a change in the pH of the brine induced by CO2 solubility in LSW enhanced interactions between the rock surface and water molecules. The respective interfacial energy then decreased, resulting in a decreasing water contact angle. It was also noticed that seawater-CO2 systems caused salt precipitation and mineralogical changes in carbonate and sandstone rock induced by calcite and kaolinite dissolution, respectively. This study contributes substantially to the understanding of interfacial properties and wettability behavior in LSW-CO2 systems, facilitating the design of LSW-CO2 EOR applications in Brazilian fields or even CO2 storage. Moreover, the study provides useful data for oil companies that have acquired mature wells and exploration blocks in Brazil, supporting them in operational and investment decisions.

Impact of design parameters on oil recovery performance in polymer flooding with low-salinity water-flooding

ABSTRACTThis study investigates the impact of design parameters on oil recovery performance in polymer flooding (PF) with low-salinity water-flooding (LSWF). Convergence technology for enhanced oil recovery (EOR) has recently been drawing attention as an upcoming technology to evolve toward similar performance and synergies. As one of the convergence technologies, PF utilizing low-salinity water is applied to improve oil recovery. In this study, an attempt is made to identify its mechanisms and to understand the low-salinity effects on PF in complex oil fields. Injection scenarios are made up to identify the efficiency of combining LSWF and PF (LSWF-PF), and sensitivity analysis is performed on the design parameters, such as slug size, salt concentration, and polymer viscosity, which are considered to be the most influential parameters. The results indicate that the efficiency of PF is significantly improved by using low-salinity water as the polymer solvent and the slug size of low-salinity water should be preferentially considered for the successful application of LSWF-PF in high-salinity reservoirs. Therefore, it is believed that a criterion can be set up to decide the design parameters of LSWF-PF, which can improve synergy effects in EOR processes.

An experimental and numerical study of low salinity effects on the oil recovery of carbonate rocks combining spontaneous imbibition, centrifuge method and coreflooding experiments

Low-salinity waterflooding (LSF) is a relatively simple and cheap Enhanced Oil Recovery technique in which the salinity of the injected water is optimized to improve oil recovery over conventional waterflooding. Sulfate-rich as well as diluted brines have shown promising potential to increase oil production in limestone core samples. To quantify the low-salinity effect, spontaneous imbibition and/or waterflooding experiments have been reported. This paper combines spontaneous imbibition, centrifuge and unsteady state (USS) coreflooding experiments to investigate low-salinity effects in carbonate samples.The experimental study used three brine compositions to investigate low-salinity effects. A high-saline Formation-water (salinity of 183.4 g/l), Sea-water (43.8 g/l) and 100-times Diluted-sea-water (0.4 g/l). Initially, a sequence of spontaneous imbibition experiments was conducted to screen the impact of connate and imbibing water composition on spontaneous oil recovery. After completing the spontaneous imbibition tests, the samples were drained inside a centrifuge to determine the impact of brine composition on residual saturation and capillary pressure. Moreover, three USS corefloodings were conducted to test the different brine compositions in secondary and tertiary injection mode. The spontaneous imbibition, centrifuge method and coreflooding tests showed a consistent trend. Compared to Formation-water and Sea-water, Diluted-sea water demonstrated the most promising potential to recover oil efficiently.The numerical part of the study includes the transparent development of a numerical centrifuge and coreflooding model on the top of the open-source simulator DuMux. The mathematical model formulation demonstrates that a simple numerical approach is sufficient to history match the centrifuge and coreflooding experiments. In line with the experimental data, the numerically derived capillary pressure and relative permeability showed an increasing water-wetting behavior as the salinity of the imbibing/injection water decreased. All implemented numerical models were validated against the commercially established Cydar software.

Oil Recovery Efficiency and Mechanism of Low Salinity-Enhanced Oil Recovery for Light Crude Oil with a Low Acid Number.

Low salinity waterflooding (low salinity-EOR) has attracted great interest from many giant oil producers and is currently under trial in some of the oil fields of the United States, Middle Eastern countries, and North Sea reservoirs. Most of the reported studies on this process were carried out for medium to relatively heavy oil with significant polar contents. In this work, we have investigated low salinity waterflooding performance for light paraffinic crude oil with a low acid number. This study has been performed using crude oil from an Indian offshore oilfield and Indian offshore seawater. Oil recovery efficiencies of seawater and its diluted versions (low salinity seawater) were evaluated through core-flooding experiments performed on a silica sand pack containing small amounts (2 wt %) of bentonite clay saturated with crude oil. Interfacial tension and wettability studies were performed to understand the associated low salinity effects on the crude oil/brine/rock properties. Effluent brine produced during the flooding experiments was also analyzed to obtain a clearer insight into the low salinity-enhanced oil recovery (EOR) mechanism. The results showed that injection of low salinity seawater can significantly increase the waterflood recovery in comparison with high salinity seawater injection. Interfacial tension and contact angle studies revealed that there is an optimum dilution level at which the interfacial tension and wettability are the most favorable for enhanced oil recovery even in the case of light paraffinic crude. These results are in line with the results obtained from the core-flooding experiments. The possible reason behind recovery improvement based on the interfacial tension and wettability studies in conjugation with the effluent brine analysis has been discussed in detail. In this study, we have observed that the enhanced oil recovery efficiency could be achieved by applying low salinity seawater flooding even in the case of light paraffinic oil with a low acid number.

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

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

Low salinity effect on the recovery of oil trapped by nanopores: A molecular dynamics study

Low salinity waterflooding (LSW) is an effective method for enhancing the oil recovery from many reservoirs, and its success has been traced to a host of low salinity effects. In this work, we perform molecular dynamics simulations to study the feasibility of recovering oil trapped by nanopores by lowering the reservoir salinity. The oil is initially trapped by a slit nanopore, with a portion of the oil protruding from the pore entrance. After the reservoir salinity is lowered, the thin brine films that separate the oil and pore walls become thicker to drive some of the trapped oil out of the pore. We quantify the free energy profile of this process and clarify the underlying molecular mechanisms. Interestingly, the brine film growth is dominated by the water transport from the brine reservoir into the pore rather than by the depletion of ions from the brine film. These results provide molecular evidence that low salinity brines benefit the recovery of the oil trapped by nanopores. They highlight that when ion depletion from thin brine films is suppressed, the osmosis of water can play a fundamental role in the expansion of the brine films; thus, the enhanced oil recovery. The slow osmosis of water through thin brine films and thus the slow displacement of oil from the pore may help explain the anomalously slow oil recovery reported in micro-modeling experiments of LSW.

Microfluidic Investigation of Low-Salinity Effects During Oil Recovery: A No-Clay and Time-Dependent Mechanism

SummaryWe present a study of the low–salinity effect during oil recovery using microfluidics experiments in an attempt to narrow the gap between pore–scale observations and porous–media–flow mechanisms, and to explain one type of low–salinity effect with delayed oil recovery and without the presence of clay. A microfluidic toolbox is used, including single–pore–scale microchannels, a pore–network–scale (approximately 102 pores) micromodel, and a reservoir–on–a–chip model (approximately 104 pores with heterogeneity), all with 2D connectivity. Experiments at the single–pore scale reveal a time–dependent oil dewetting and swelling behavior when a crude–oil droplet is in contact with low–salinity water. An interplay between water chemical potential and oil–phase polar compounds explains this pore–scale observation well. Experiments at the pore–network scale illustrate that the dewetting and swelling of residual oil in the swept region increase the water–flow resistance, modifying the flow field and thus redirecting the flooding liquid into unswept regions. This pore–network–scale effect is re–expressed into a macroscale model as a sweep–efficiency improvement derived from the change of relative permeabilities, which requires time to develop. Finally, experiments on our “reservoir–on–a–chip” model show significant incremental oil recovery during tertiary low–salinity waterflooding and confirm that late–time sweep–efficiency improvement contributes to most of the incremental oil recovery. On the basis of this microfluidic framework, we emphasize the following three findings: Low–salinity tertiary waterflooding can improve oil recovery by an improvement of sweep efficiency, which is a consequence of residual–oil dewetting and swelling.The low–salinity effect can occur without the existence of clay.The wettability alteration and oil swelling are time–dependent processes and should be expressed as a function of oil/water contact time rather than dimensionless time [pore volume (PV)], which explains some observations from previous coreflood experiments.

An experimental study of Nanosilica application in reducing calcium sulfate scale at high temperatures during high and low salinity water injection

The deposition of inorganic scales, especially calcium sulfate (CaSO4), in oil reservoirs causes damages not only in the reservoir, but also in production equipment, injection facilities, and production and injection tubing. In the present study, it was aimed to evaluate the formation damage potential of high and low salinity water injection and effects of Nanosilica particles on the formation damage reduction during water injection. For this reason, first, the nanoparticles were synthesized and characterized and then, using the electrical conductivity test, the suitable concentration of Nanosilica was obtained to be about 0.1 wt%. Afterwards, series of coreflood tests were performed on a sandstone core sample. The results showed that low salinity water injection causes less damage when sulfate ion exists in the solution. However, once the injection water is desulfated, the controlling factor of damage is the salinity difference of formation and injection waters. The lower the salinity difference between the injection and formation waters at the higher temperatures, the less formation damage due to scales deposition. Based on our results, Nano particles are more effective when they are added to a high salinity injection water and can greatly prevent scale depositions at dynamic conditions. However, the temperature rise had a negative impact on their performance. These later findings were found to be directly correlated with zeta potential (ZP) values of the solutions. Finally, our observations revealed that incorporating Nanosilica particles with low salinity water injection could not be a suitable remedy towards reducing formation damage due to inorganic scales deposition even at low temperatures where ZP is high.

Direct pore-scale visualization of interactions between different crude oils and low salinity brine

Direct pore-scale visualizations using micromodels for low salinity water injection (LSWI) have revealed that the contact between low salinity water and crude oil can provoke formation of water-in-oil micro-dispersions. This experimental work, using a number of different crude oils, aims to visually study the link between micro-dispersion formation and pore surface wettability alteration by low salinity water injection. The effect of aging time on wettability alteration by LSWI was investigated. It was observed that mixed-wet conditions established with a moderate aging time would increase low salinity ability controlled by the oil characteristics. Moreover, under tertiary LSWI, the trapped oil was mobilized if the crude oils exhibited capabilities of forming micro-dispersions. Interestingly, when a crude oil with little or no propensity to form micro-dispersions was used, low salinity effects such as wettability alteration and improved oil recovery were absent. Also, micromodel experiments could enable the investigation of LSWI for waxy crude oil, which is difficult to do with other approaches. To demonstrate the impact of micro-dispersion formation on polar components of the oils, infrared analyses were performed indicating the importance of oil polar agents enriched in aromatics and sulfoxides on controlling the formation of the micro-dispersions. After using various crude oils, it was concluded that the effectiveness of LSWI as the method to increase oil recovery is predominantly controlled by two factors; (i) initial degree of wettability of pore surfaces and (ii) the propensity of crude oil to form micro-dispersions.

Conditions for a Low-Salinity Enhanced Oil Recovery (EOR) Effect in Carbonate Oil Reservoirs

Low-salinity enhanced oil recovery (EOR) effects have for a long time been associated with sandstone reservoirs containing clay minerals. Recently, a laboratory study showing low-salinity EOR effects from composite carbonate core material was reported. In the present paper, the results of oil recovery by low-salinity water flooding from core material sampled from the aqueous zone of a limestone reservoir are reported. Tertiary low-salinity effects, 2–5% of original oil in place (OOIP), were observed by first flooding the cores with high-saline formation water (208 940 ppm) and then with 100× diluted formation water or 10× diluted Gulf seawater at 110 °C. It was verified by flooding the core material with distilled water that the core samples contained small amounts of anhydrite, CaSO4(s). The oil recovery was tested under forced displacement using different injection brines and oils with different acid numbers, 0.08, 0.34, and 0.70 mg of KOH/g. The low-salinity effect depended upon mixed wet conditions, a...

Pore scale observation of low salinity effects on outcrop and oil reservoir sandstone

Enhanced oil recovery has been observed in sandstone reservoirs when the salinity of the injected water is decreased during water flooding. In core plug tests, enhancement ranges from 5 to 38% over traditional water flooding using sea water or formation water. Previous work suggests that clays must be present in the reservoir, the oil must have polar components and divalent cations must be present in the formation water, but there is no clear explanation of exactly what controls the molecular level processes at the interface between the fluid and the sand grain surfaces. We have used a new method, atomic force mapping, where functionalised atomic force microscopy (AFM) tips feel a surface, to simulate the interaction between mineral, water and crude oil, under a variety of salinity conditions. We used contact mode AFM to image the internal pore surfaces from fresh outcrop sandstone and from reservoir sandstone that had been cleaned with strong solvents, the traditional treatment method for samples used in core plug testing. We see features that suggest clay nanoparticles attached to the sand grain surfaces. The tips were functionalised with carboxylic acid to model adhesion of polar components in crude oil to pore surfaces. Adhesion forces were extracted from force maps generated while the samples were exposed to solutions of high salinity (artificial seawater, ASW, 36,500 ppm) and low salinity (diluted ASW, 1400 ppm). The maps displayed heterogenous adhesion, which in some cases could be linked to features on the surface. The low salinity effect was observed on most sand grains from the sandstones; there was no significant difference in behaviour for the outcrop and solvent cleaned reservoir samples. Adhesion decrease ranged from 0 to 57% with an average of about 30%. For most cases, the effect was reversible when the salinity was changed, even through several salinity change cycles, and the effect was consistent on several individual sand grains.

Short-term low-salinity response in lead-exposed lobsters, Homarus americanus (Milne Edwards)

The only effect attributable solely to lead exposure (50μg·l −1, 30 days) in lobsters, Homarus americanus (Milne Edwards), was decreased pentose shunt activity (G6PDH) in the antennal gland, which contained the greatest concentration of lead taken up by the tissues analyzed. Similarly-exposed lobsters were subsequently held for 2 days in clean, aerated sea water at either ambient or low salinity (27 or 17%., respectively), after which time the lead concentration in the antennal gland had dropped by one-third and G6PDH had returned to control values. Low-salinity effects far outnumbered lead-induced effects and were found primarily in the tail muscle, corroborating findings in an earlier study with cadmium. In that earlier study, cadmium produced more metabolic disturbance than did the lead exposure reported here. Lead exposure at low salinity abolished several normal hyposaline reactions seen in control animals.

Low-salinity stress in the American lobster,Homarus americanus, after chronic sublethal exposure to cadmium: Biochemical effects

Lobsters(Homarus americanus) were exposed to cadmium (6µg l−1, 30 days) in flowing seawater, then held for 7 days in aerated “clean ” seawater at either ambient (27 ‰) or low (17 ‰) salinity. Cadmium exposure alone (ambient salinity) induced a general elevation of enzyme activity (heart, antennal gland, and muscle MDH; heart LDH and GPI), despite the probability of some clearance of cadmium from body tissues during the “clean ” seawater holding period. Low-salinity alone (non-exposed lobsters) caused a decrease of enzyme activity (AAT, LDH, GPI, PK) in most tissues examined, except for tail muscle IDH, the activity of which was increased, and MDH, which was significantly elevated above ambient controls in all tissues except heart. Most low-salinity effects were observed in tail muscle, and most cadmium effects, in heart; low-salinity effects outnumbered cadmium stress by nine to four. In heart and tail muscle of cadmium-exposed lobsters held at low salinity, each of the two stresses apparently operated to nullify the other's effects. The most prominent single biochemical response to these sublethal stresses was the elevation of MDH activity. The ratio MDH: LDH gave the clearest indication of overall relative stress.