Low Salinity Injection Research Articles

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.

Spontaneous Imbibition Test of Low Salinity Injection at Low Saline Waxy Crude Carbonate

Low salinity waterflooding (LSW) is categorized as one of emerging EOR technologies. It is done by injecting water with different salt composition and/or concentration. The research has been carried out for both sandstone and carbonate with the results looks promising. However, most of this research still concentrated in the north sea, middle east and North America region. This article discusses the applicability of low salinity waterflooding methodology in Indonesia. Spontaneous imbibition test is carried out to observe the recovery gain from a various combination of concentration and composition of the injected brine. The change of pH of the brine is also examined in order to confirm the pH effect mechanism. Three different concentration of brine (500 ppm, 5.000 ppm, and 10.000 ppm), three different brine composition (NaCl, CaCl2, and MgCl2) and high paraffinic crude oil are used as the fluid sample. It is found that the increased oil recovery is significant at a salinity of 10,000 ppm for MgCl2 and 5,000 ppm for NaCl ions. While the lowest recovery was shown by the test at a salinity of 500 ppm

Quantification of wettability characteristics for carbonates using different salinities

Low salinity water flooding has received strong interest recently. It has been reported that injecting low salinity water can improve oil recovery in carbonate reservoirs through wettability alteration, whose mechanism however remains unclear, especially regarding the contributions from adsorbed polar organic components. This work investigates systematically the key parameters that govern the complex interactions of rock/brine/crude oil in carbonate reservoirs. The effects of crude oil composition and salinity on surface wettability alteration are studied by using three types of dead oil from Norwegian and North Sea with various acid numbers and two types of carbonate rocks (outcrop-calcite and subsurface-dolomite). Ion-substitution-adsorption is evaluated using the infrared spectrometer (IFR) and energy-dispersive X-ray spectroscopy (EDX). Oil/brine interactions by means of the interfacial tension (IFT) and contact angle as a function of oil composition, rock type, and salinity are experimentally investigated. The IFR and EDX data indicate a compositional change when the carbonate minerals are in touch with saline solutions, supporting the proposed rock-brine interaction mechanism. The salinity effect is more salient at the liquid/rock interface than the liquid/liquid interface, and the response to the brine composition is highly dominated by the oil composition with respect to its content of polar organic components. There is a reduction of contact angle as the seawater water is diluted twice while its influence on the IFT is small, and the effect is more pronounced for dolomite rock, showing different results for different crude oils used. This suggests that the wettability alteration of carbonate rock is an intricate phenomenon that is influenced not only by the salinity but also by the chemical composition of crude oil and rock mineralogy. A combination of three possible mechanisms, including multiple ion exchange, EDL expansion (electrokinetics repulsive), and salting-out, is discussed to illustrate the mechanism of wettability alteration during low salinity injection.

Low salinity water injection: Impact of physical diffusion, an aquifer and geological heterogeneity on slug size

This paper uses numerical simulation to investigate the impact of physical diffusion/dispersion on oil recovery from low salinity water injection. It focuses particularly on how slug size is affected by the interaction of longitudinal and transverse mixing with reservoir heterogeneity and an aquifer. Previous work, which focussed only on the impacts of longitudinal dispersion in a homogeneous reservoir, suggested that a slug size of ∼0.4 PV would recover almost as much oil as continuous low salinity water injection. This study suggests that a slug size of at least 0.6 PV is needed in heterogeneous reservoirs, in the absence of an aquifer. The presence of an aquifer in combination with diffusion means that even very large slugs are degraded to the point where there is little benefit from low salinity injection. These conclusions apply whether low salinity water is injected immediately production begins or following conventional, high salinity waterflooding. In layered systems, transverse diffusion can result in significant improvements to incremental oil recovery over that which would be achieved in the absence of diffusion.

An experimental study of the low salinity Smart Water - Polymer hybrid EOR effect in sandstone material

Previously reported experimental work has shown positive oil recovery effects by combining low salinity brine with polymer for injection into sandstone cores. The extra oil recovered by the combination of the two EOR methods was termed a “Hybrid EOR effect”.The experimental work performed in the present study assessed the potential of combining low salinity (LS) Smart Water injection with polymer (P) flooding; LSP flooding. Dramatic improvements in the EOR effect were observed when combining LS in secondary mode with polymer injection in tertiary mode.Secondary LS injection gave 59 %OOIP after 1 PV injected, which is an outstanding result compared to secondary formation water (FW) injection reaching only 35 %OOIP after 1 PV, and an ultimate recovery of 40 %OOIP after 2.5 PV. The ultimate recovery with seawater (SW) in secondary mode was 44% OOIP, showing only a slightly better performance than FW, but poorer efficiency than the ultimate LS brine recovery of 64 %OOIP.In comparison, the ultimate recovery with secondary LSP injection was 66 %OOIP. The displacement front was stable and fast, but it did not give a substantial increase in oil recovery in comparison to the secondary LS injection. Tertiary LSP injection after secondary LS injection gave the highest oil recoveries with a total hybrid EOR effect of 86 %OOIP. All tertiary LSP floods gave improved displacement stability with EOR effects of ∼20 %OOIP. The positive EOR effects are a result of redistribution of oil within the pore space after wettability alteration with the Smart Water. Oil attached to the mineral surface has low mobility, but at more water-wet conditions a new fraction of mobile oil, which is more easily mobilized with a polymer solution, is created (Wang et al., 2001).The combination of Smart Water with polymer flooding appears to have a huge potential for future EOR applications. Field development strategies for new sandstone reservoirs should include wettability alteration and redistribution of oil within the pores by Smart Water and improved displacement efficiency with polymer for optimized EOR to lowest cost.

Pore network modelling of low salinity water injection under unsteady-state flow conditions

In this work, we describe a dynamic pore network model that has been developed to investigate the effects of low salinity (LS) water injection on oil recovery under dynamic flow conditions. For the first time, we introduce a formulation whereby the evolving spatial distribution of brine salinity is explicitly tracked during unsteady-state secondary and tertiary LS floods. Phases are updated in capillary elements according to the relative balance between capillary and viscous forces, the former being correlated to salinity through a functional relationship between effective contact angle (i.e. wettability) and local brine concentration.We have investigated the impact of several key parameters on secondary and tertiary LS injection, including: injection rate, viscosity ratio, and salinity-induced wettability modifications. We have implemented a stochastic approach throughout in order to assess statistical variability in recovery outcomes. For the particular network architecture studied, simulations have shown a range of results for different induced wettability changes. When the contact angle variation shifted the system from strongly oil-wet to weakly oil-wet, most cases exhibited a small positive secondary LS effect but negligible tertiary benefit. Greater variation in LS outcome was observed when LS brine modified pores to close to neutral-wet conditions – a generally positive secondary LS effect was seen but there were several exceptions dependent upon frontal advance rate and viscosity ratio, where the displacement regime could switch from capillary-dominated flow to viscous fingering. Salinity modification of wettability to a water-wet configuration resulted in positive secondary LS displacement and a positive tertiary LS effect.The study shows that the impact of LS injection can often be difficult to predict a priori for any given combination of rock/fluid parameters and laboratory protocol, due to the complex way in which the underlying parameters interact. When compared against high salinity (HS) data, both positive and negative LS effects have been observed depending upon the prevailing system properties and the timing of LS initiation. However, by running a series of network modelling simulations, we are able to identify areas of parameter space that are more likely to elicit a positive LS response. In particular, we observe that a change in the dominant flow regime (capillary fingering, viscous fingering, frontal advance) may be induced by the injection of LS brine and this has been found to play an important role in determining LS efficacy.

Smart Water injection strategies for optimized EOR in a high temperature offshore oil reservoir

Smart Water injection is an EOR technique that is both environmentally friendly and easily implementable to a fractional cost compared to other water-based EOR methods. EOR by Smart Water is a wettability alteration process towards more water-wet conditions, which induces increased positive capillary forces and increased microscopic sweep efficiency.The objective of this work was to evaluate the injection strategy for Smart Water in an offshore high temperature sandstone reservoir, and compare the efficiency of seawater-based injection brines with low salinity brines, which can behave as Smart Water in sandstone reservoirs. Oil recovery experiments have been performed at reservoir conditions using preserved reservoir cores and reservoir fluids.Secondary low salinity injection gave an average of 33.5 %OOIP extra oil produced, compared to modified seawater injection. The tertiary low salinity EOR effect after modified seawater flooding gave an average of 11.8 %OOIP extra oil. Significant changes in produced water pH from initially acidic to alkaline conditions during low salinity injection were observed, favoring wettability alteration towards more water-wet conditions.The results confirmed that low salinity brine behaved as a Smart Water, contributing with significant extra oil recovery in a high temperature sandstone reservoir. Introducing Smart Water from day one in a reservoir, i.e. in secondary recovery mode, is significantly more efficient, regarding both response time and ultimate oil recovery, than tertiary mode Smart Water injection.

The impact of monovalent and divalent ions on wettability alteration in oil/low salinity brine/limestone systems

Waterflooding is applied worldwide to improve oil recovery. Due to the complexity of the crude oil-brine-rock interactions, the mechanism behind the low saline enhanced oil recovery (EOR) process has been debated in the literature for the last decade. Both physical and chemical mechanisms have been proposed, but it appears that none of the suggested mechanisms have got a general acceptance in the scientific literature so far. The main objective of this paper is to investigate the affinity of ions toward the surface during low and high salinity injection by measuring the contact angle (CA) and interfacial tension (IFT) in a carbonate rock substrate/oil/brine system, in different salinity and pH levels. The brines were original sea and formation water, brine solutions containing single component salt such as; MgSO4, KCl, Na2SO4, CaCl2, MgCl2, NaCl, and multicomponent mixtures of them at different concentrations. Three different stock-tank crude oils are utilized in this study. Results showed that the asphaltenic-acidic crude oils have a positive impact to wettability alteration of carbonate rocks during low salinity water injection. Also we observed that the low salinity waterflooding possibly behaving similar to alkaline flooding due to increase in pH. The IFT results show that the lowest IFT value is obtained at 5000ppm smart water containing divalent ions, Mg2+ and SO42−.

Technology Focus: Heavy Oil (March 2017)

Technology Focus Over a 6-month time frame in 2016, I was able to attend three SPE conferences on heavy oil in different countries spanning three continents (Canada, Peru, and Kuwait). Despite regional differences in the applications, potentials, problems, and technological needs, the common theme in all conferences was “low cost.” Cost optimization in heavy-oil production was discussed from technical and economic perspectives, not only in the technical sessions but also in numerous panel discussions. Such optimization can be achieved through numerical modeling to suggest general optimal strategies and development plans or by using proper real-time data acquisition (production optimization) for prompt decisions while operations are ongoing. This requires continuous monitoring of the processes as seen in many steam-assisted-gravity-drainage operations or other types of steam-injection applications. I selected two papers about advanced monitoring techniques as suggested reading in this issue. Moreover, chemical and nanomaterial additives to water and steam have received a great deal of attention. Low-interfacial-tension (microemulsion) and low-salinity injection in heavy oils in sands and carbonates and wettability alteration in carbonates were common topics at conferences held over the past year. I selected one review paper for additional reading and one experimental work as a summary paper on this subject. Apparently, modeling efforts on advanced (but unconventional) technologies such as electromagnetic heating have continued. You will find a detailed mathematical analysis of the process in one of the papers summarized. Despite the recent economic downturn, we were able to hear the outcome of current field practices at pilot or demonstration scale. Papers detailing small-scale cyclic-steam-injection applications in Kuwait and Oman were worth reading, and one article on this specific subject is included here. Considering these activities in the Middle East, effective transfer of technologies from North America to that part of the world will become highly critical in the near future. Recommended additional reading at OnePetro: www.onepetro.org. SPE 181160 State-of-the-Art Review of the Steam Foam Process by Eric Delamaide, IFP Technologies Canada, et al. SPE 180732 An Integrated Probabilistic Work Flow for Primary and Thermal Performance Prediction of a Large Extraheavy-Oil Field by Raushan Kumar, Chevron, et al. SPE 181431 Horizontal Steam-Injection Flow Profiling Using Fiber Optics by Mahdy Shirdel, Chevron Energy Technology Company, et al. SPE 180726 SAGD Production Observations Using Fiber-Optic Distributed Acoustic and Temperature Sensing: SAGD DAS—Listening to Wells To Improve Understanding of Inflow by Warren MacPhail, Devon, et al.

Using high- and low-salinity seawater injection to maintain the oil reservoir pressure without damage

The oil reservoir pressure declines due to oil production, and this decline will lead to reduction in the oil productivity. The reservoir pressure maintenance is a practice in the oil industry in which seawater is injected into the aquifer zone below the oil zone to support the reservoir pressure. Calcium sulfate scale is one of the most serious oilfield problems that could be formed in sandstone and carbonate reservoirs. Calcium sulfate may precipitate during the injection of seawater with high sulfate content into formation brine with high calcium content. Mixing seawater and formation water may cause precipitation of calcium sulfate, barium sulfate, and/or strontium sulfate. Seawater treatment does not remove the entire sulfate ions from the injected water. Low sulfate concentrations may cause damage. Enhanced oil recovery processes such as smart water injection, which originally is diluted seawater, may cause calcium sulfate precipitation as the reduction of water salinity will increase the sulfate precipitation and decrease its solubility. This study was conducted to investigate the damage caused by the deposition of calcium sulfate precipitation. A solution is proposed to prevent the damage due to calcium sulfate by using chelating agents. Several coreflooding experiments were conducted using Berea sandstone and Indiana limestone cores at reservoir conditions of pressure and temperature using seawater (high and low salinity) and formation water. Chelating agents used in this study are: EDTA (ethylenediaminetetraacetic acid), HEDTA (hydroxyethylenediaminetriacetic acid), and HEIDA (hydroxyethyliminodiacetic acid). HEDTA and HEIDA chelating gents are environmentally friendly and can be used in marine environment. High-salinity water injection caused severe formation damage, and the injectivity will decline faster compared to the low-salinity water injection. HEDTA and EDTA chelating agents at low concentrations performed better than HEIDA chelating agents in both Berea sandstone and Indiana limestone cores. HEDTA and EDTA chelating agents were able to prevent the damage due to calcium sulfate precipitation and enhanced the core permeability.

Direct visualization of pore-scale fines migration and formation damage during low-salinity waterflooding

Formation damage due to fines migration results, potentially, in significant decreases in reservoir permeability and, hence, the recoverability of crude oil from reservoirs. On the other hand, low salinity brine injection is a promising technique for increasing oil recovery from clay-rich sandstones in an economic manner. Clay detachment at low salinity conditions, however, drastically alters fluid flow. In this work, clay-functionalized etched-silicon micromodels are used to visualize directly the mobilization of clay at low salinity conditions in (i) the absence of oil, and (ii) the presence of oil. Study results include clay mobilization and pore plugging in the absence and presence of oil visualized by saturating the clay-functionalized micromodel with high salinity brine followed by injections of reduced salinity brines. Clay detachment and migration was observed in oil-free systems for 4000 ppm NaCl low salinity injection brine. The extent of fines detachment was quantified to determine the types of clay structures affected. Furthermore, fines migration, flocculation, and re-deposition were visualized directly. The types of structures formed (i.e., pore-plugging, pore-lining, etc.) by the re-deposited clay particles are characterized to determine their impact on formation damage. Clay detachment in the presence of oil was also visualized. Initial conditions analogous to clastic reservoirs were established by allowing the crude oil, brine, and solids to interact (i.e., age). Clay detachment occurred during 4000 ppm NaCl low salinity oil recovery. Real-time, pore-level visualization revealed significant mechanisms during oil recovery processes and their influence on multiphase flow. Specifically, pore plugging particles in water-filled pores obstructed preferential flow paths and diverted injection fluid to unswept regions thereby increasing oil production.

Low salinity injection into asphaltenic-carbonate oil reservoir, mechanistical study

The impacts of salinity adjustment of displacing fluid have recently gained special attention to enhanced oil recovery (EOR). Different mechanisms have been studied widely in the literature while some of them are still subjugated to more scrutiny. The effects of diluted sea water on the interfacial properties of brine and asphaltenic-acidic crude oil and the wettability alteration of carbonate reservoir rock are investigated in this experimental observational work. The measurements of interfacial tension (IFT) and contact angle (CA) as two main parameters are studied. Besides, the effects of asphaltene and resin in the crude oil on the IFT values between the crude oil and aqueous solution are investigated.The experimental results show that the lowest IFT values are obtained at high salinity conditions, while the surface rock wettability alterations are observed at low salinity conditions. Based on the obtained results, a combined mechanism is proposed to describe the wettability alteration towards more water wet at low salt conditions.

Potential applications of time-lapse CSEM to reservoir monitoring

Monitoring of changes in brine chemistry (salinity and temperature), during water-flooding is important for injector optimisation, understanding efficiency, detecting early water breakthrough, locating bypassed hydrocarbons or detecting scaling in the heterogeneous reservoir. It is already known that water injection into the oil-leg of a hydrocarbon reservoir can be monitored by both seismic acquisition and also CSEM methods. The problem of an interfering pressure signal for seismic impacts quantitative evaluation for time-lapse analysis, while with EM there are the counterbalancing effects of salinity and temperature. CSEM becomes favoured when the pressure effects on seismic are dominant, or heavy oil is present with similar acoustic properties as the formation and injected waters. The quality of measurement for both methods is influenced by reservoir facies variations, acquisition repeatability and overburden heterogeneity. Time-lapse seismic is unlikely to detect brine distributions injected into the water-leg or aquifer, although it may detect associated pressure up effects. However, our calculations show that it may be possible for time-lapse CSEM to distinguish the inter-mixing of different brines in the subsurface hydrocarbon reservoir. Specifically, low salinity injection or injection into a highly saline formation can clearly be detected with this technique.

Enhanced Oil Recovery (EOR) by Combining Surfactant with Low Salinity Injection

When injecting low salinity (LS) water, it is believed that destabilization of oil layers adhering to mineral surfaces could be a contributing mechanism to enhanced oil recovery (EOR). Surfactant flooding is a proven EOR technique by increasing the capillary number. The combination of LS water at reduced capillarity can avoid retrapping of destabilized oil and exceed recoveries of either of the techniques applied alone. In this study, we have used an alcohol propoxy sulfate mixed with an internal olefin sulfonate to compare the oil recovery in a low salinity surfactant (LSS) flooding process at moderately low IFTs to that of an optimal salinity surfactant (OSS) injection process at ultralow IFT. The surfactant formulation was selected on the basis of an initial screening phase using a North Sea crude oil and diluted seawater. Its effect on oil recovery efficiency in different injection scenarios was investigated using crude oil aged Berea sandstone cores. The results showed comparable recoveries for the L...

Study of low-salinity waterflooding for single- and two-phase experiments in Berea sandstone cores

Abstract Single-phase experiments were carried out in Berea sandstone to understand the behavior of the water–rock system and establish a baseline to interpret multiphase experiments. The water–rock reactions at microscopic level are reflected in the macroscopic scale by alteration in permeability in the rock and pH in the effluent. In our experiments we assume that the significant changes are solely a result of the alteration of the brine salinity since the composition of the brine and mineralogy of the core were held constant. Injection of brine with 1% salinity produced permanent permeability reduction due to fines release. Two-phase experiments were carried out on undamaged and damaged Berea sandstone cores. Comparison of single-phase and two-phase experiments results in undamaged Berea cores that showed the same pressure and pH behavior when low salinity waterflooding is performed. Incremental oil production was observed in both undamaged and damaged cores suggesting that the mechanism of incremental production during low salinity injection is not solely related to fines migration.

Study of the Effect of Injection Water Quality on the Interfacial Tension of ASP/Crude Oil

Abstract ASP (Alkali/Surfactant/Polymer) flooding has been successfully applied in several field pilots in the Daqing oil field in China. Oil recovery has improved by about 20% OOIP over recovery by waterflooding. The interfacial tension (IFT) of ASP/crude oil is one of the most important factors that control the effectiveness of ASP flooding. The effects of alkali, surfactant, polymer and oil properties on IFT were previously studied. This paper addresses the effect of injection water quality on the IFT of ASP/crude oil. This paper analyzes the inorganic ion compositions and organic compounds of injected water in different pilots in Daqing. The effect of these compositions and the suspended particles in injection water on the IFT of ASP/oil were studied. A carboxylate surfactant was used in the study. All experiments were carried out at 45 °C. Results showed that the suspended particles had little influence on IFT, and that inorganic ion compositions had some influence to a certain extent but were not the main factor affecting IFT for the low salinity injection water used in ASP flooding in the Daqing oil field. The main factor increasing the IFT is certain organic compounds in the injection water. The paper points out the main types of organic compounds influencing IFT. Some methods to lower IFT by controlling water quality are proposed. Introduction ASP (Alkali/Surfactant/Polymer) flooding technology was discovered in the early 1980's(1–3). Based on the cooperative effect of the three chemicals, ASP synergizes the three chemicals' functions and improves their efficiencies much more than singly. At the sametime, it greatly reduces the amount of the chemicals needed; especially the expensive surfactant. With crude oil having a high acid number, ASP flood field tests obtained reasonably high recovery(4,5). The crude oil in the Daqing oil field is paraffin based with a low acid number; < 0.1 mg KOH/g. In the laboratory, the Daqing oil field obtained rather high recovery for a crude oil with such a low acid number(6). Five ASP pilot tests were successfully performed in different well patterns, well spacings and reservoir conditions in the field. These pilot tests show that ASP flooding unequivocally enlarges the sweep volume, improves the displacement efficiency and produces incremental recovery of more than 20% OOIP than does waterflooding(7–9). There are many complex factors that can affect the efficiency of ASP flooding, such as the interfacial tension (IFT) of ASP/crude oil, adsorption loss of the ASP solution in the formation, the viscosity and emulsification property of the ASP solution and the compatibility of the ASP solution with the reservoir. IFT is one of the most important factors for determining the appropriate ASP injection solution. Measurement of IFT is the first step to determining the prescription for applying the ASP solution. According to capillary theory, under the conditions of the pressure gradient that can be reached through present technology, in order to activate the residual oil left by waterflooding, IFT of ASP/crude oil should be decreased to a 10−3 mN/m level.