Mechanism Of Low Salinity Water Flooding Research Articles

Review on Underlying Mechanisms of Low Salinity Waterflooding: Comparisons between Sandstone and Carbonate

Review on Underlying Mechanisms of Low Salinity Waterflooding: Comparisons between Sandstone and Carbonate

Visual investigation of the effect of clay-induced fluid flow diversion on oil recovery, as a low-salinity water flooding mechanism

Low-salinity water flooding (LSWF) is an EOR method applicable to both sandstone and carbonate reservoirs. In recent years, LSWF has become an attractive technique but still some uncertainties concerning the governing mechanisms exist in studies. Mechanisms such as wettability alteration, osmosis, and fluid flow diversion by fines migration are proposed to explain the incremental oil recovery by LSWF in sandstones. Flow diversion is still being debated as to whether this mechanism works and, if it does, to what extent. This mechanism occurs due to clay swelling and fines migration, which results in pores blockage, diversion of the fluid flow to unswept areas, and enhanced oil displacement. Hence, the presence of clays is claimed to be a necessity for the success of LSWF in sandstone reservoirs. Here we proposed a new approach to study effects of different mechanisms of LSWF alone and in combination of each other using micromodels to track fluid flow diversion and the reason behind it and its subsequent benefits in case of oil recovery, visually. In this paper micromodel tests in different wetting and clay presence conditions were designed and conducted to investigate the standalone fluid flow diversion mechanism and the combination of it with wettability alteration and osmosis effects during LSWF. Tests conducted in water wet and oil wet states showed that the presence of clays is not the main criterion for activating the LSWF effect and the initial wettability is more critical. Our studies showed that the fluid flow diversion share in oil recovery is only 30% of the total incremental oil displaced by LSWF, while about 70% of the oil is produced by wettability alteration and osmosis mechanisms. It is reasonable to say that, although flow diversion is an active mechanism, it is not the dominant one and on the other hand wettability alteration is.

Molecular dynamics simulation for the effect of cation replacement on the oil-brine-rock interaction

The low salinity waterflooding can increase oil recovery by 5%-20% in sandstones, which has attracted more and more attention. However, the mechanism of low salinity waterflooding is not clear. In this paper, the effect of cation replacement on the interaction between oil and silica is investigated via molecular dynamics simulation to reveal the mechanism of low salinity waterflooding. The results show that the stable adsorption of oil droplets on the silica surface is mainly due to the strong interaction between oil and rock caused by cations. Replacing Ca2+ with Na+ can effectively reduce the interaction between oil and rock and make oil droplets easier to be peeled off. This work is helpful for the further study of the oil-brine-rock interaction and can provide theoretical guidance for the oil film stripping of sandstone reservoir.

Assessment of low salinity waterflooding in carbonate cores: Interfacial viscoelasticity and tuning process efficiency by use of non-ionic surfactant

Hypothesis. A large number of papers discuss merits and mechanisms of low salinity waterflooding. For each mechanism proposed, there are counter examples to invalidate the stated mechanism. The effect of wettability from low salinity water, which is predominantly stated in literature as the dominant mechanism, may not be valid. We introduce a direct correlation between oil-brine interfacial viscoelasticity and oil recovery from waterflooding.Experiments. The oil recovery is investigated in carbonate rocks for three light crude oils, by injection of a wide range of aqueous phases, ranging from deionized water to very high salinity brine of 28 wt%, and low concentration of a non-ionic surfactant at 100 ppm. The oil-brine interfacial viscoelasticity is quantified and supplementary measurements of interfacial tension and wettability are performed.Findings. In our experiments, oil recovery is higher from high salinity water injection than from low salinity water injection. A strong relationship is observed between interface elasticity and oil recovery for different concentrations of salt in the injected brine as well as for ultra-low concentration surfactant. An elastic oil-brine interface results in high oil recovery. The surfactant molecule we have selected prefers the oil–water interface despite high solubility in the oil phase and makes ultra-low concentration of 100 ppm in injection water very effective. Contrary to widespread assertions in the literature, we find no definitive correlation between oil recovery and wettability.

Low salinity waterflooding: Surface roughening and pore size alteration implications

Multiple mechanisms of low salinity waterflooding (LSW) orchestrate the increase of oil recovery. One proposed mechanism is surface roughening which alters the wettability in pores. However, clay swelling that generates surface roughening also simultaneously reduces the pore size. Therefore, we study the implication of surface roughening and pore size of the rock that leads to oil recovery in LSW at different brine compositions and clay contents. We measure the incremental oil recovery due to brine dilution sequences by using a modified-Amott imbibition cell. The results suggest that oil recovery due to brine dilution is minimal when the cores have clay content above 20%. The pore size alteration effects compete with surface roughening. We find that the presence of divalent ions hinders the clay swelling. This implies a smaller pore size alteration and the least amount of surface roughening. In addition, the evolutions of deduced pore size distribution through T2 NMR confirm the results of LSW imbibition. Further, zeta potential measurements on the sandstone suspension provide the surface-charge to understand the oil recovery mechanism. This research suggests that the pore size alteration and surface roughening are important mechanisms for incremental oil recovery in sandstone during LSW operation. These findings might aid the rational design of LSW in the future.

Review of low salinity waterflooding mechanisms: Wettability alteration and its impact on oil recovery

Low salinity waterflooding (LSW) has attracted attention of numerous researchers as a promising technique for enhanced oil recovery, yet its application is still limited because of incomplete mechanisms and unreliable predictions. This paper summarizes relevant mechanisms for predicting responses of LSW. Since the wettability alteration is generally regarded as the most important one among possible LSW mechanisms, two aspects of predicting LSW responses are reviewed: prediction of wettability alteration and effects of wettability alteration on oil recovery. For the first aspect, the importance of more quantitative prediction of wettability alteration is addressed because experimental results have suggested that the optimal wettability may not be water-wet as imagined. From the relation between wettability and interaction forces in the oil-brine-rock systems, mechanisms of wettability alteration are reviewed along with quantitative calculation. The extended Derjaguin-Landau-Verwey-Overbeek (DLVO) theory, which has been often used to calculate the contact angles, is not available to obtain an accurate contact angle anymore. For the second aspect, an overview of the optimal wettability for oil recovery is given with relevant pore-scale fluid mechanisms. Though experiments found the maximum oil recovery from weakly water-wet or neutral wet rocks, the results were not elaborate enough to reveal the relation between the contact angle and the oil recovery. The pore-scale simulation is a powerful tool to investigate such relations but so far it still needs further developments on scaling and validations with experimental data.

Investigation on the micro-flow mechanism of enhanced oil recovery by low-salinity water flooding in carbonate reservoir

Low-salinity water flooding has become a significant way to develop carbonate reservoirs in recent years. Clarifying the micro-flow mechanism of low-salinity water flooding (LSWF) on enhanced oil recovery (EOR) becomes the focus of this issue. In this paper, firstly, we conducted a series of experiments to prove that LSWF can improve the recovery of carbonate reservoirs. And then, a new relative permeability model and water content calculation model are established considering interface micro-forces and capillary pressure. The result shows that the present model has good agreement with the experimental results, which can characterize the micro-displacement mechanism of LSWF. The recovery rate can be increased by 9% compared with the formation water flooding (FWF). Under low-salinity conditions, the wettability of rock surface is changed by the chemical reaction of divalent ions (Ca2+, Mg2+, SO42−), which shows more hydrophilic. And the optimal salinity of the brine range from 1400 mg/L to 3200 mg/L. Besides, LSWF can reduce the residual oil saturation, which is the macro cause for EOR. This study has provided a quick and reasonable guide to know the micro-flow mechanism of LSWF and theoretical basis for development of carbonate reservoirs by LSWF.

Effect of salinity on oil production: review on low salinity waterflooding mechanisms and exploratory study on pipeline scaling

The past decades have witnessed a rapid development of enhanced oil recovery techniques, among which the effect of salinity has become a very attractive topic due to its significant advantages on environmental protection and economical benefits. Numerous studies have been reported focusing on analysis of the mechanisms behind low salinity waterflooding in order to better design the injected salinity under various working conditions and reservoir properties. However, the effect of injection salinity on pipeline scaling has not been widely studied, but this mechanism is important to gathering, transportation and storage for petroleum industry. In this paper, an exhaustive literature review is conducted to summarize several well-recognized and widely accepted mechanisms, including fine migration, wettability alteration, double layer expansion, and multicomponent ion exchange. These mechanisms can be correlated with each other, and certain combined effects may be defined as other mechanisms. In order to mathematically model and numerically describe the fluid behaviors in injection pipelines considering injection salinity, an exploratory phase-field model is presented to simulate the multiphase flow in injection pipeline where scale formation may take place. The effect of injection salinity is represented by the scaling tendency to describe the possibility of scale formation when the scaling species are attached to the scaled structure. It can be easily referred from the simulation result that flow and scaling conditions are significantly affected if a salinity-dependent scaling tendency is considered. Thus, this mechanism should be taken into account in the design of injection process if a sustainable exploitation technique is applied by using purified production water as injection fluid. Finally, remarks and suggestions are provided based on our extensive review and preliminary investigation, to help inspire the future discussions.

Sulphate Ion Interference on Oil Recovery Mechanism of Low Salinity Waterflooding in Dolomite Reservoirs

This study focused on the sulphate ion concentration interference with different divalent cations ratio, used in low salinity water flooding in dolomite reservoirs by comparing the oil recovery with the altered amount of divalent cations dissolved in brine, occurred from rock surface equilibrium shifting. The oil recovery from injecting different potential determining ions concentration is measured by core flood experiment. The process of detecting the amount of divalent cations begins with establishing oil adsorption on the dolomite grain surface. Then, the grain is stirred in brine with different formula, which is later titrated in order to gather the desired data. Finally, the phenomena occurred during flooding with different potential determining ion concentration is described by combining the result of oil recovery with altered amount of divalent ions. The results showed that at high temperature (70°C), the oil recovery from each case is not much different because high amount of calcium sulphate precipitation can be compensated by high rate of rock dissolution and magnesium carboxylate complex formation. However, at low temperature (30°C), the oil recovery tends to be lower when the sulphate concentration is higher because calcium ion tends to form or precipitate with sulphate ion rather than forming the carboxylate complex. Due to low dissolution rate, the amount of calcium ion is insufficient for oil recovery mechanism, especially when the sulphate ion concentration exceeds the solubility limit. Furthermore, for the case that the ratio of magnesium to calcium ion is high, it is observed that some amount of magnesium ion can form the carboxylate complex to compensate the lost amount of calcium ion. From the result, it can be concluded that at low temperature, which the dissolution reaction occurs slowly, the effect of changing the divalent cation ratio, including sulphate concentration, is large because the formation of magnesium carboxylate complex is not much at this temperature, however calcium sulphate precipitation reduces the number of active calcium ions in oil recovery mechanism. On the other hand, because the dissolution reaction occurs faster and the formation of magnesium carboxylate complex is more favourable at high temperature, therefore the values of oil recovery, even at different concentration of potential determining ions, are not much different at this temperature. Furthermore, it is also found that the carboxylate complex formation can be induced by high concentration of either type of divalent ions when the sulphate ion concentration is not too high.

Direct insights into the pore-scale mechanism of low-salinity waterflooding in carbonates using a novel calcite microfluidic chip

One of the key open questions in the area of low or controlled salinity water flooding (LSWF or CSWF) is how the observed oil recovery at macro-scale (e.g. Darcy or core-scale) can the explained and what underlying microscopic mechanisms drive it. Thus far, the micromodel investigation of LSWF has been limited to sandstones, remaining challenging to apply to carbonates. In this paper we aim to i) extend the capability to fabricate a novel calcite micromodel using Iceland spar calcite crystal, ii) investigate the pore-scale mechanisms leading to oil recovery from carbonates.A target crude oil-brine-rock (COBR) system was first selected. To screen potential brines which can produce low-salinity-effect (LSE) and to guide the design of the micromodel experiments, contact angle measurements were carried out using two methods: i) contact angle under fixed, and ii) under dynamic salinity condition. The micromodel displacement experiments were then performed by flooding an oil saturated model with high salinity water followed by low salinity water injection to displace the high salinity water and observe any potential changes to the configuration and saturation of the residual oil. Additionally, the effect of connate water presence on the efficiency of LSE was investigated. To account for the time effects of the low salinity process, the experiments were monitored for an extended time period in order of several days to a month.For the COBR system studied in the micromodel, the results clearly show that when brine salinity is lowered the microscopic sweep efficiency is improved; providing a direct in-situ evidence for wettability alteration to a more water-wetting state. The presence of connate water enhanced the efficiency of LSWF both in terms of speed (time-scale) and quantity of oil recovery. It is postulated that in the presence of connate water an initial water-film around the calcite surface is present which facilitates the diffusive transport of brine ions when low salinity is injected. Thus it is favorable to have an initial water film present; a case for mixed-wettability. We observed that the oil production was non-instantaneous characterized by a prolonged induction time and a slow “layer-by-layer” recovery either from the pore body or throat wall; a process we refer to as “peel-off”. Before the oil can be removed from the calcite surface, de-wetting (or de-pinning) patterns were formed which grew and coalesced toward formation of a clearly visible larger pattern. Ultimately, the remaining oil under low salinity was comparatively much less compared to the end of high salinity step.The observed mechanism of the oil recovery and the slow associated time have direct implications for the pore-scale simulation of the process and upscaling to Darcy-scale, and the design of laboratory experiments to avoid false negative results. They would also likely imply lack of a clear oil-bank observation at core scale.

Effects of low-salinity waterflooding on capillary pressure hysteresis

In this study, low-salinity waterflooding enhanced-oil recovery mechanisms linked to the water–crude oil interfacial viscoelastic response are investigated considering a distinct interfacial effect, namely the water-crude oil interfacial viscoelasticity response. In contrast, wettability alteration is interpreted through analysis of capillary hysteresis. A capillary pressure experimental setup used in our previous research, is utilized here to capture capillary hysteresis. Moreover, new improvements over the traditional quasi-static porous plate method have been implemented to accelerate measurements. The dynamic-static method, i.e. a combination of continuous injection in drainage and stepwise quasi-static method in imbibition on short (<1″ long) core samples, was found to capture the correct envelopes of the capillary pressure curves in a much shorter time span. Two pairs of experiments were conducted to investigate the interfacial visco-elasticity and wettability alteration effects on capillary hysteresis. One pair is conducted on Minnelusa formation rock samples and diluted TC crude oil at 30°C and without any significant aging to minimize wettability alteration. Two core plugs were flooded with high-salinity and low-salinity brines, separately. Results show that low-salinity brine can still increase oil recovery even in the absence of wettability alteration. This is attributed to the formation of a more visco-elastic brine-crude oil interface upon exposure to low-salinity brine, leading to a more continuous oil phase. Two additional experiment pairs were conducted on Berea and TC oil at high temperature (70°C). Two cores were subject to the same experimental conditions except that one was allowed to age with crude oil for 3weeks. This aging process was found to render the rock more oil wet, resulting in more pronounced capillary hysteresis and less oil recovery. Our study shows effects of two mechanisms, i.e. fluid–fluid interfacial visco-elasticity and wettability alteration, separately. The interpretation of our unique capillary pressure datasets sheds light on low-salinity waterflooding mechanisms.

Analysis of capillary pressure and relative permeability hysteresis under low-salinity waterflooding conditions

In this work, we analyze measurements of drainage, spontaneous imbibition and forced imbibition capillary pressure curves in conjunction with two-electrode resistivity on sandstone core samples under low- and high-salinity waterflooding conditions. State-of-the-art laboratory equipment able to work with actual reservoir fluids at reservoir conditions was designed and built to conduct these measurements. Unsteady-state coreflooding experiments under similar experimental conditions to those in the capillary pressure tests were also carried out. A black-oil reservoir simulation model was set up to history match experimental production and pressure data to obtain multi-phase flow functions. Two experiments were conducted on Minnelusa formation (eolian sand) rock samples at 93°C with TC crude oil and synthetic brines. Placement of an oil-wet membrane on one plug end and a water-wet disk on the other end guaranteed that only one phase was able to flow through each sample end at any given time. In one experiment, a 57,491ppm-brine (High-Salinity) was used during the imbibition process, while a 20-fold dilution of the High-Salinity brine (Low-Salinity) was used in the other experiment. Correspondingly, two unsteady-state experiments at fixed injection rate were completed on Minnelusa formation rock samples placed in the coreflooding system using comparable experimental conditions as those in the capillary pressure experiments. Comparison of high- and low-salinity experimental results shows that more noticeable capillary hysteresis toward water-wetness arose in the low-salinity experiment. High-salinity experiment results showed that the imbibition resistivity index was higher than that corresponding to drainage. History matching of the transient production data in capillary pressure experiments along with end-points obtained from unsteady-state core flooding experiments was used to obtain relative permeability curves. Availability of high-quality capillary pressure data at reservoir conditions improved the accuracy of relative permeability curves obtained from history matching unsteady-state core flooding experiments. Our results show a substantial improvement in obtaining both capillary pressure and relative permeability curves at reservoir conditions resulting from a combination of steady- and unsteady-state experiments. Capillary pressure results confirm that hysteresis is more prominent under low-salinity conditions and apparent higher oil trapping is observed during imbibition, compared to high-salinity conditions. Unsteady-state coreflooding results also show that low-salinity brine is not conducive to enhanced oil recovery in low-salinity waterflooding. Geochemical effects appear to negatively impact beneficial interfacial mechanisms proposed to benefit oil recovery such as the formation of more viscoelastic interfaces under low-salinity conditions. We conclude that coupling of fluid–fluid and rock–fluid interactions, including geochemical reactions, needs to be accounted for to better explain low-salinity waterflooding mechanisms.

Critical review of low-salinity waterflooding

It was observed that higher oil recovery could be obtained when low-salinity (LS) water flooded a core of high-salinity initial water about 15 years ago. Such low-salinity waterflooding benefit or effect has drawn the oil industry attention since then. In the recent years, many researchers conducted laboratory corefloods, and several companies carried field tests. The objectives of these efforts were (1) to conform the benefits and (2) find the mechanisms of such benefit. Although most of the results confirmed the positive effect, some results showed no benefit. Many mechanisms have been proposed, but there is no consensus of the dominant mechanism(s). The oil industry is continuing the effort to discover the effect. This paper is to provide a critical review of the results and to summarize the achievements of the industry׳s effort. This paper aims to provide the status of the art. The information provided in this paper hopefully will help to speed up our further efforts to explore this effect. The following contents are reviewed: (1) history of low-salinity waterflooding; (2) laboratory observations; (3) field observations; (4) working conditions of low-salinity effect; (5) mechanisms of low-salinity waterflooding; and (6) simulation of low-salinity waterflooding. In this paper, the mechanisms proposed in the literature and their validity are discussed. • Provide a comprehensive review of lab results, field observation and all proposed mechanisms. • Discuss the validity of each mechanism. • Provide the personal view of possible effects of low-salinity waterflooding in real field-scale.