scholarly journals Role of Monovalent and Divalent Ions in Low-Salinity Water Flood in Carbonate Reservoirs: An Integrated Analysis through Zeta Potentiometric and Simulation Studies

Energies ◽  
2021 ◽  
Vol 14 (3) ◽  
pp. 729
Author(s):  
Paras H. Gopani ◽  
Navpreet Singh ◽  
Hemanta K. Sarma ◽  
Padmaja Mattey ◽  
Vivek R. Srivastava
Keyword(s):  
Zeta Potential ◽  
Oil Recovery ◽  
Reservoir Simulation ◽  
Saturation Index ◽  
Mineral Dissolution ◽  
Wettability Alteration ◽  
Integrated Analysis ◽  
Simulation Studies ◽  
Low Salinity ◽  
Monovalent Ions

The presence of principal ions in the water injected is essential for enhanced oil recovery by formation of water-wet state in carbonates. This study reaffirms this and presents an evaluation of the positive influence of both divalent as wells as monovalent ions on wettability alteration mechanisms during low salinity waterflooding using brines of varying ionic composition, referred to as “smart brines”. Zeta potentiometric analysis and reservoir simulation studies were conducted with diluted and smart brines that were prepared by varying the composition of principal ions. Surface charge of oil-saturated whole core samples of rock in the presence of various diluted and smart brines was estimated by zeta potential measurements. A comprehensive analysis of zeta potentiometric and reservoir simulation studies was done to establish and investigate the linkage between the recovery mechanism and the incremental recovery achieved. It is noted that zeta potential increases with the increasing level of dilution and it can be attributed to electric double-layer mechanism. On the contrary, simulation studies implied a different mechanism where an increase in effluent’s pH and Ca2+ mole fraction along with decrease in moles of minerals and saturation index implied rock dissolution was dominant mechanism. Moreover, the effect of mineral dissolution beyond the injection block is highly doubtful. This study demonstrates that an integrated approach from both zeta potentiometric and simulation studies can be used to provide insights into the underlying science of interactions at pore scale during a low salinity waterflood using smart brines. With the aid of an adequately designed upscaling procedure and protocol, the laboratory results can be further used towards developing field-scale models to obtain with realistic recovery factors with optimized brine composition and salinity.

Impact of clay type and water composition on low salinity water injection – visualisation approach

2018 ◽  
Vol 58 (1) ◽  
pp. 51 ◽  
Author(s):  
Tammy Amirian ◽  
Manouchehr Haghighi
Keyword(s):  
Oil Recovery ◽  
Wettability Alteration ◽  
Oil Film ◽  
Low Salinity ◽  
Water Composition ◽  
Low Salinity Water ◽  
Monovalent Ions ◽  
Salinity Water ◽  
The Impact ◽  
Clay Type

Low salinity water (LSW) injection as an enhanced oil recovery method has attracted much attention in the past two decades. Previously, it was found that the presence of clay such as kaolinite and water composition like the nature of cations affect the enhancement of oil recovery under LSW injection. In this study, a pore-scale visualisation approach was developed using a 2D glass micromodel to investigate the impact of clay type and water composition on LSW injection. The glass micromodels were coated by kaolinite and illite. A meniscus moving mechanism was observed and the oil–water interface moved through narrow throats to large bodies, displacing the wetting phase (oil phase). In the presence of kaolinite, the effect of LSW injection was reflected in the change to the wettability with a transition towards water-wetness in the large sections of the pore walls. The advance of the stable water front left behind an oil film on the oil-wet portions of pore walls; however, in water-wet surfaces, the interface moved towards the surface and replaced the oil film. As a result of wettability alteration towards a water-wet state, the capillary forces were not dominant throughout the system and the water–oil menisci displaced oil in large portions of very narrow channels. This LSW effect was not observed in the presence of illite. With regard to the water composition effect, systems containing divalent cations like Ca2+ showed the same extent of recovery as those containing only monovalent ions. The observation indicates a significant role of cation exchange in wettability alteration. Fines migration was insignificant in the observations.

Synergistic Effects of Engineered Water-Nanoparticle on Oil/Brine/Rock Interactions in Carbonates

2021 ◽  
Author(s):  
Ibraheem Salaudeen ◽  
Muhammad Rehan Hashmet ◽  
Peyman Pourafshary
Keyword(s):  
Contact Angle ◽  
Zeta Potential ◽  
Interfacial Tension ◽  
Oil Recovery ◽  
Sea Water ◽  
Hybrid Methods ◽  
Carbonate Reservoir ◽  
Wettability Alteration ◽  
Combined Effects ◽  
Low Salinity

Abstract Nano particle-assisted engineered water is one of the newest hybrid methods of Enhanced Oil Recovery (EOR) that is gaining attention in the oil and gas industry. This is attributed to the low cost of the technique and environmental friendliness of the materials involved. Low salinity and ions adjustment of the injection brine has been reported to be very useful for improving oil production in carbonates, and application of nanoparticles (NPs) to improve oil recovery via different mechanisms such as wettability alteration, interfacial tension reduction, disjoining pressure and viscosity modification. This paper therefore investigates the combined effects of these two techniques on oil-brine-rock (OBR) interactions in carbonate reservoirs. Caspian Sea Water salinity of 13000 ppm was synthesized in the laboratory, potential determining ions such as Mg2+, Ca2+ and SO42- were adjusted to obtain the desired engineered waters used as dispersant for SiO2 nanoparticle. A series of experiments were performed ranging from zeta potential, interfacial tension, contact angle, electron scanning environmental imaging, pH analysis and particle size to determine the optimum formulation of engineered low salinity brine and nanoparticle. The salinities and concentration of NP considered in this experimental study ranges between (3,250 - 40,000) ppm and (0.05 - 0.5) wt.%, respectively. It was observed that optimum homogenization time for achieving stability of the chosen nanofluid without using stabilizer is 45 minutes. Four times sulphate and calcium ions in the engineered water reduced the contact angle from 163 to 109 and 151 to 118 degrees respectively. However, in the presence of NP, the contact angle further reduced to a very low values of 5 and 41 degrees. This confirms the combined effects of EW and that of nanofluid (NF) in altering wettability from the hydrophobicity state to hydrophilicity one that rapidly improves oil recovery in carbonate reservoir. IFT measurements were made between oil and formation brine as well as between oil and different EWs at room temperature. The Formation water has the least value of interfacial tension- 15mN/m. Four times diluted sea water spiked with four times sulphate is denoted as 4dsw4S. The zeta potential values showed dsw4S-NF to be the most stable, whereas EW-NF spiked with 4 times Mg2+ show detrimental effects on NF stability. The nanoparticles sizes were measured to be less than 50 nm. Rheological studies of the EW-NF at different temperatures (25, 40, 60 and 80 degrees Celsius) shows similar trend of Newtonian and non-Newtonian behavior at shear rate less than 100 and above 100 per seconds respectively. We conclude that spiking calcium ion and sulphate ion into the injected brine in combination with 0.1wt% NP yielded the wettability alteration in carbonate rock samples. The significant reduction in wettability is attributed to the combined effects of the active mechanisms present in the hybrid method and is considerably better than each standalone technique.

Injectivity and Potential Wettability Alteration of Low-Salinity Polymer in Carbonates: Role of Salinity, Polymer Molecular Weight and Concentration, and Mineral Dissolution

SPE Journal ◽  
2021 ◽  
pp. 1-24
Author(s):  
Maissa Souayeh ◽  
Rashid S. Al-Maamari ◽  
Ahmed Mansour ◽  
Mohamed Aoudia ◽  
Thomas Divers
Keyword(s):  
Contact Angle ◽  
Porous Medium ◽  
Oil Recovery ◽  
Mineral Dissolution ◽  
Mobility Control ◽  
Spontaneous Imbibition ◽  
Wettability Alteration ◽  
Rock Surface ◽  
Low Salinity ◽  
Oil Displacement

Summary Coupling polymer with low-salinity water (LSW) to promote enhanced oil recovery (EOR) in carbonate reservoirs has attracted significant interest in the petroleum industry. However, low-salinity polymer (LSP) application to improve oil extraction from such rocks remains a challenge because of the complex synergism between these two EOR agents. Thus, this paper highlights the main factors that govern the LSP displacement process in carbonate reservoirs in terms of wettability alteration and mobility control. A series of experiments including contact angle, spontaneous imbibition, injectivity, adsorption, and oil displacement tests were performed. The impact of mineral dissolution on the polymer/brine and polymer/rock surface interactions and its possible connection to the efficiency of the LSP in carbonates was also investigated using ζ potential analysis following an elaborative procedure. All experiments were executed at elevated temperature (75°C) using two polymers (SAV10) of different molecular weights (MWs) prepared at varying concentrations and salinities. Contact angle measurements showed that increasing the polymer concentration and MW and, at the same time, decreasing the solution salinity could effectively rend homogeneous oil-wet calcite surfaces strongly water-wet. Conversely, spontaneous imbibition tests using heterogonous oil-wet Indiana limestone cores showed that the polymer viscosity and its molecular size hinder the performance of the polymer to modify the wettability of the core samples at high concentration and MW because they could limit its penetration into the porous medium. On the other hand, the results obtained from polymer injectivities showed that LSP had better propagation with lower filtration effects in comparison with high-salinity polymer (HSP). However, polymer adsorption and inaccessible pore volume (IPV) increased with the decrease of salinity. Calcite mineral dissolution triggered by LSP, which is associated with an increase in pH and [Ca2+], considerably influenced the polymer viscosity. In addition, ζ potential measurements showed that the LSP altered the rock surface charge from positive toward negative and at the same time, the Ca2+ released due to mineral dissolution could modify the polymer molecule charge toward positive. This confirms that mineral dissolution impressively results in better wettability alteration performance; however, it could lead to undesirable high polymer adsorption at low salinity. These findings provide new insight into the influence of mineral dissolution on polymer performance in carbonates. Finally, forced oil displacement tests revealed that both HSP and LSP extracted approximatively the same amount of oil. The HSP could enhance the oil recovery through mobility control. By contrast, wettability alteration could take part in the improvement of oil recovery at LSP, as proved by spontaneous imbibition tests, along with mobility control. Despite possessing high wettability alteration potential, LSP could not yield very high recovery because of its low accessibility into the porous medium. Shearing of the LSP was found effective in improving oil recovery through enhancing the polymer accessibility. This will lead us to simply say that polymer accessibility into carbonates is crucial for the success of the wettability alteration and mobility control processes, which is remarkably important not only for this specific study but also for other various polymer EOR applications.

A Comparison of Different Nanoparticles' Effect on Fine Migration by Low Salinity Water Injection for Oil Recovery: Introducing an Optimum Condition

2021 ◽  
pp. 1-22 ◽  
Author(s):  
Ali Madadizadeh ◽  
Alireza Sadeghein ◽  
Siavash Riahi
Keyword(s):  
Porous Media ◽  
Zeta Potential ◽  
Oil Recovery ◽  
Fine Particles ◽  
Production Equipment ◽  
Water Flooding ◽  
Sand Production ◽  
Low Salinity ◽  
Low Salinity Water ◽  
Salinity Water

Abstract Today, enhance oil recovery (EOR) methods are attracting more attention to increase the petroleum production rate. Some EOR methods such as low salinity water flooding (LSW) can increase the amount of fine migration and sand production in sandstone reservoirs which causes a reduction in permeability and inflict damages on to the reservoir and the production equipment. One of the methods to control fine migration is using nanotechnology. Nanoparticles (NPs) can reduce fine migration by various mechanisms such as reducing the zeta potential of fine particles' surfaces. In this paper, three NPs including SiO2, MgO, and Al2O3 's effects on controlling fine migration and sand production were investigated in two scenarios of pre-flush and co-injection by using sandpack as a porous media sample. When NPs are injected into the porous media sample, the outflow turbidity and zeta potential of particles decreases. Experiments showed that SiO2 has the best effect on controlling fine migration in comparison with other NPs and it could reduce fine migration 69% in pre-flush and 75% in co-injection. Also, MgO and Al2O3 decreased fine migration 65% and 33% in the pre-flush scenario and 49%,13% in the co-injection scenario, respectively.

scholarly journals A mechanistic investigation of low salinity water flooding coupled with ion tuning for enhanced oil recovery

RSC Advances ◽  
2020 ◽  
Vol 10 (69) ◽  
pp. 42570-42583
Author(s):  
Rohit Kumar Saw ◽  
Ajay Mandal
Keyword(s):  
Enhanced Oil Recovery ◽  
Oil Recovery ◽  
Water Flooding ◽  
Wettability Alteration ◽  
Rock Surface ◽  
Calcite Dissolution ◽  
Low Salinity ◽  
Low Salinity Water ◽  
Mechanistic Investigation ◽  
Salinity Water

The combined effects of dilution and ion tuning of seawater for enhanced oil recovery from carbonate reservoirs. Dominating mechanisms are calcite dissolution and the interplay of potential determining ions that lead to wettability alteration of rock surface.

Phase Behavior, Wettability Alteration, and Oil Recovery of Low-Salinity Surfactant Solutions in Carbonate Reservoirs

SPE Journal ◽  
2020 ◽  
Vol 25 (04) ◽  
pp. 1784-1802 ◽  
Author(s):  
Sepideh Veiskarami ◽  
Arezou Jafari ◽  
Aboozar Soleymanzadeh
Keyword(s):  
Phase Behavior ◽  
Oil Recovery ◽  
Wettability Alteration ◽  
Study Phase ◽  
Low Salinity ◽  
Angle Measurements ◽  
Contact Angle Measurements ◽  
Favorable State ◽  
Phase Behaviors ◽  
The Impact

Summary Recent investigations have shown that treatment with injected brine composition can improve oil production. Various mechanisms have been suggested to go through the phenomenon; nevertheless, wettability alteration is one of the most commonly proposed mechanisms in the literature. Wettability alteration of the porous media toward a more favorable state reduces the capillary pressure, consequently contributing to the oil detachment from pore walls. In this study, phase behavior, oil recovery, and wettability alteration toward a more favorable state were investigated using a combination of formulations of surfactant and modified low-salinity (LS) brine. Phase behaviors of these various formulations were examined experimentally through observations on relative phase volumes. Experiments were performed in various water/oil ratios (WORs) in the presence of two different oil samples, namely C1 and C2. These experiments were conducted to clarify the impact of each affecting parameter; in particular, the impact of resin and asphaltene of crude oil on the performance of LS surfactant (LSS) flooding. Hereafter, the optimal formulation was flooded into the oil-wet micromodel. Optimum formulations increased the capillary number more than four orders of magnitude higher than that under formation brine (FB) flooding, thus causing oil recovery rates of 61 and 67% for oil samples C1 and C2, respectively. Likewise, the wettability alteration potential of optimized formulations was studied through contact angle measurements. Results showed that LS and LSS solutions could act as possible wettability alternating methods for oil-wet carbonate rocks. Using the optimum formulation resulted in a wettability alteration index (WAI) of 0.66 for sample C1 and 0.49 for sample C2, while using LS brine itself ended in 0.51 and 0.29 for oil samples C1 and C2, respectively.

Interfacial Viscoelasticity of Crude Oil/Brine: An Alternative Enhanced-Oil-Recovery Mechanism in Smart Waterflooding

SPE Journal ◽  
2018 ◽  
Vol 23 (03) ◽  
pp. 803-818 ◽  
Author(s):  
Mehrnoosh Moradi Bidhendi ◽  
Griselda Garcia-Olvera ◽  
Brendon Morin ◽  
John S. Oakey ◽  
Vladimir Alvarado
Keyword(s):  
Crude Oil ◽  
Water Chemistry ◽  
Enhanced Oil Recovery ◽  
Oil Recovery ◽  
Interaction Mechanism ◽  
Field Trials ◽  
Wettability Alteration ◽  
Low Salinity ◽  
Injection Water

Summary Injection of water with a designed chemistry has been proposed as a novel enhanced-oil-recovery (EOR) method, commonly referred to as low-salinity (LS) or smart waterflooding, among other labels. The multiple names encompass a family of EOR methods that rely on modifying injection-water chemistry to increase oil recovery. Despite successful laboratory experiments and field trials, underlying EOR mechanisms remain controversial and poorly understood. At present, the vast majority of the proposed mechanisms rely on rock/fluid interactions. In this work, we propose an alternative fluid/fluid interaction mechanism (i.e., an increase in crude-oil/water interfacial viscoelasticity upon injection of designed brine as a suppressor of oil trapping by snap-off). A crude oil from Wyoming was selected for its known interfacial responsiveness to water chemistry. Brines were prepared with analytic-grade salts to test the effect of specific anions and cations. The brines’ ionic strengths were modified by dilution with deionized water to the desired salinity. A battery of experiments was performed to show a link between dynamic interfacial viscoelasticity and recovery. Experiments include double-wall ring interfacial rheometry, direct visualization on microfluidic devices, and coreflooding experiments in Berea sandstone cores. Interfacial rheological results show that interfacial viscoelasticity generally increases as brine salinity is decreased, regardless of which cations and anions are present in brine. However, the rate of elasticity buildup and the plateau value depend on specific ions available in solution. Snap-off analysis in a microfluidic device, consisting of a flow-focusing geometry, demonstrates that increased viscoelasticity suppresses interfacial pinch-off, and sustains a more continuous oil phase. This effect was examined in coreflooding experiments with sodium sulfate brines. Corefloods were designed to limit wettability alteration by maintaining a low temperature (25°C) and short aging times. Geochemical analysis provided information on in-situ water chemistry. Oil-recovery and pressure responses were shown to directly correlate with interfacial elasticity [i.e., recovery factor (RF) is consistently greater the larger the induced interfacial viscoelasticity for the system examined in this paper]. Our results demonstrate that a largely overlooked interfacial effect of engineered waterflooding can serve as an alternative and more complete explanation of LS or engineered waterflooding recovery. This new mechanism offers a direction to design water chemistry for optimized waterflooding recovery in engineered water-chemistry processes, and opens a new route to design EOR methods.

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

2020 ◽  
Vol 75 ◽  
pp. 50 ◽  
Author(s):  
Tao Zhang ◽  
Yiteng Li ◽  
Chenguang Li ◽  
Shuyu Sun
Keyword(s):  
Oil Recovery ◽  
Rapid Development ◽  
Preliminary Investigation ◽  
Petroleum Industry ◽  
Phase Field Model ◽  
Scale Formation ◽  
Wettability Alteration ◽  
Reservoir Properties ◽  
Low Salinity ◽  
Low Salinity Waterflooding

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.

Chelating-Agent Enhanced Oil Recovery for Sandstone and Carbonate Reservoirs

SPE Journal ◽  
2015 ◽  
Vol 20 (03) ◽  
pp. 483-495 ◽  
Author(s):  
M. A. Mahmoud ◽  
K. Z. Abdelgawad
Keyword(s):  
Zeta Potential ◽  
Oil Recovery ◽  
Chelating Agents ◽  
Water Injection ◽  
Chelating Agent ◽  
Carbonate Reservoirs ◽  
Low Salinity ◽  
Low Salinity Water ◽  
Salinity Water ◽  
Core Permeability

Summary Recently low-salinity waterflooding was introduced as an effective enhanced-oil-recovery (EOR) method in sandstone and carbonate reservoirs. The recovery mechanisms that use low-salinity-water injection are still debatable. The suggested possible mechanisms are: wettability alteration, interfacial-tension (IFT) reduction, multi-ion exchange, and rock dissolution. In this paper, we introduce a new chemical EOR method for sandstone and carbonate reservoirs that will give better recovery than the low-salinity-water injection without treating or diluting seawater. In this study, we introduce a new chemical EOR method that uses chelating agents such as ethylenediaminetetraacetic acid (EDTA), hydroxyethylethylenediaminetriacetic acid (HEDTA), and diethylenetriaminepentaacetic acid (DTPA) at high pH values. This is the first time for use of chelating agents as standalone EOR fluids. Coreflood experiments, interfacial and surface tensions, and zeta-potential measurements are performed with DTPA, EDTA, and HEDTA chelating agents. The chelating-agent concentrations used in the study were prepared by diluting the initial concentration of 40 wt% with seawater and injecting it into Berea-sandstone and Indiana-limestone cores of a 6-in. length and a 1.5-in. diameter saturated with crude oil. The coreflooding experiments were performed at 100°C and a 1,000-psi backpressure. Low-salinity-water and seawater injections caused damage to the reservoir because of the calcium sulfate scale deposition during the flooding process. The newly introduced EOR method did not cause calcium sulfate precipitation, and the core permeability was not affected. The core permeability was measured after the flooding process, and the final permeability was higher than the initial permeability in the case of chelating-agent injection. The coreflooding effluent was analyzed for cations with the inductively coupled plasma (ICP) spectroscopy to explain the dissolution-recovery mechanism. The effect of iron minerals on the rock-surface charge was investigated through the measurements of zeta potential for different rocks containing different iron minerals. HEDTA and EDTA chelating agents at 5 wt% concentration prepared in seawater were able to recover more than 20% oil from the initial oil in place from sandstone and carbonate cores. ICP measurements supported the rock-dissolution mechanism because the calcium, magnesium, and iron concentrations in the effluent samples were more than those in the injected fluids. The IFT-reduction mechanism was confirmed by the low IFT values obtained in the case of chelating agents. The type and concentration of chelating agents affected the IFT value. Higher concentrations yielded lower IFT values because of the increase in carboxylic-group concentration. We found that the high-pH chelating agents increased the negative value of zeta potential, which will change the rock toward more water-wet.

scholarly journals Sandstone Reservoir Wettability Alteration Due to Water Softening: Impact of Silica Nanoparticles on Sand Production Mechanism

2020 ◽  
Vol 10 (5) ◽  
pp. 6328-6342 ◽  
Keyword(s):  
Contact Angle ◽  
Silica Nanoparticles ◽  
Oil Recovery ◽  
Reservoir Rock ◽  
Wettability Alteration ◽  
Sand Production ◽  
Thin Sections ◽  
Low Salinity ◽  
Low Salinity Water ◽  
Salinity Water

Low salinity water in the oil reservoirs changes the wettability and increases the oil recovery factor. In sandstone reservoirs, the sand production occurs or intensifies with wettability alteration due to low salinity water injection. In any case, sand production should be stopped and there are many ways to prevent sand production. By modifying the composition of low salinity water, it can be adapted to be more compatible with the reservoir rock and formation water, which has the least formation damage. By eliminating magnesium and calcium ions, smart soft water (SSW) is created which is economically suitable for injection into the reservoirs. By stabilizing the nanoparticles in SSW, nanofluids can be prepared which with injection into the sandstones reservoir increase the oil recovery, change the wettability and increase the rock strength. In this present, SSW composition was determined by compatibility testing, and the SiO2 nanoparticle with 1000 ppm concentration was stabilized in SSW. Eight thin sections were oil wetted by using normal heptane solution and different molars of stearic acid and two thin sections were considered as base thin sections to compare the effect of wettability alteration on sand production. Thin sections were immersed in SSW and Nanofluid, the amount of contact angle and sand production were measured in both cases. The amount of sand produced and the contact angle in SSW was higher than the Nanofluid. The silica nanoparticles reduced the contact angle (more water wetting) and by sitting between the sand particles, more than 40%, it reduced sand production.

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