Effect and Mechanism of CO2 Electrochemical Reduction for CCUS-EOR

Abstract Unconventional reservoir plays an increasingly important role in the world energy system, but its recovery is always quite low. Therefore, the economic and effective enhanced oil recovery (EOR) technology is urgently required. Moreover, with the aggravation of greenhouse effect, carbon neutrality has become the human consensus. How to sequestrate CO2 more economically and effectively has aroused wide concerns. Carbon Capture, Utilization and Storage (CCUS)-EOR is a win-win technology, which can not only enhance oil recovery but also increase CO2 sequestration efficiency. However, current CCUS-EOR technologies usually face serious gas channeling which finally result in the poor performance on both EOR and CCUS. This study introduced CO2 electrochemical conversion into CCUS-EOR, which successively combines CO2 electrochemical reduction and crude oil electrocatalytic cracking both achieves EOR and CCUS. In this study, multiscale experiments were conducted to study the effect and mechanism of CO2 electrochemical reduction for CCUS-EOR. Firstly, the catalyst and catalytic electrode were synthetized and then were characterized by using scanning electron microscope (SEM) & energy dispersive X-ray spectroscopy (EDS) and X-ray photoelectron spectroscopy (XPS). Then, electrolysis experiment & liquid-state nuclear magnetic resonance (1H NMR) experiments were implemented to study the mechanism of CO2 electrochemical reduction. And electrolysis experiment & gas chromatography (GC) & viscosity & density experiments were used to investigate the mechanism of crude oil electrocatalytic cracking. Finally, contact angle and coreflooding experiments were respectively conducted to study the effect of the proposed technology on wettability and CCUS-EOR. SEM & EDS & XPS results confirmed that the high pure SnO2 nanoparticles with the hierarchical, porous structure, and the large surface area were synthetized. Electrolysis & 1H NMR experiment showed that CO2 has converted into formate with the catalysis of SnO2 nanoparticles. Electrolysis & GC & Density & Viscosity experiments indicated that the crude oil was electrocatalytically cracked into the light components (<C20) from the heavy components (C21∼C37). As voltage increases from 2.0V to 7.0V, the intensity of CO2 electrocchemical reduction and crude oil electrocatalytic cracking enhances to maximum at 3.5V (i.e., formate concentration reaches 6.45mmol/L and carbon peak decreases from C17 to C15) and then weakens. Contact angle results indicated that CO2 electrochemical reduction and crude oil electocatalytic cracking work jointly to promote wettability alteration. Thereof, CO2 electrochemical reduction effect is dominant. Coreflooding results indicated that CO2 electrochemical reduction technology has great potential on EOR and CCUS. With the SnO2 catalytic electrode at optimal voltage (3.5V), the additional recovery reaches 9.2% and CO2 sequestration efficiency is as high as 72.07%. This paper introduced CO2 electrochemical conversion into CCUS-EOR, which successfully combines CO2 electrochemical reduction and crude oil electrocatalytic cracking into one technology. It shows great potential on CCUS-EOR and more studies are required to reveal its in-depth mechanisms.

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Microscale Effects of Polymer on Wettability Alteration in Carbonates

SPE Journal ◽

10.2118/200251-pa ◽

2020 ◽

Vol 25 (04) ◽

pp. 1884-1894

Author(s):

Zuoli Li ◽

Subhash Ayirala ◽

Rubia Mariath ◽

Abdulkareem AlSofi ◽

Zhenghe Xu ◽

...

Keyword(s):

Contact Angle ◽

Crude Oil ◽

Oil Recovery ◽

Polymer Solutions ◽

High Salinity ◽

Adhesion Force ◽

Contact Angles ◽

Wettability Alteration ◽

Injection Water ◽

Lower Contact

Summary Polymer enhances the volumetric sweep efficiency through the increased viscosity of injection water and subsequently results in enhanced oil recovery. Most of the reported experimental studies focused on only evaluating polymer viscosifying characteristics and their associated significance for achieving adequate mobility control in porous media. The microscale effects of polymer on wettability alteration in carbonates are rarely studied. In this experimental investigation, the wettability of carbonates in the presence of polymer was measured using contact angle tests. In addition, the adhesion force between carbonate and crude oil droplets in polymer solutions was determined using a custom-designed integrated thin-film drainage apparatus equipped with a bimorph sensor. The liberation kinetics of crude oil from carbonate surfaces were also measured by an optical microscope-based liberation cell to understand the wettability alteration effects on oil recovery. All the experiments, except the adhesion force, which was measured at room temperature due to the restriction of bimorph sensor, were conducted at both ambient and elevated temperatures (70°C) using a sulfonated polyacrylamide polymer (SPAM) (at 500 and 700 ppm) in high-salinity injection water. Deionized (DI) water was used as a baseline to provide a representative comparison with the high-salinity brine. The contact angles of crude oil droplets on a carbonate surface were highest in DI water and decreased in brine. The addition of polymer decreased the contact angle further, with higher concentrations of polymer resulting in a lower contact angle. The adhesion force between crude oil and carbonate showed good agreement with contact angle data, and the oil adhesion was smallest on the carbonate surface in the presence of polymer. The crude oil liberation from the carbonate surface by flooding with brine and polymer was found to be more efficient at elevated temperature than at ambient temperature, consistent with lower contact angles measured in these aqueous solutions at high temperature. The equilibrium oil liberation degree with polymer solutions increased by more than two times when the temperature was increased from 23 to 70°C. The higher liberation degree obtained with polymer solutions also correlated well with the lowest adhesion force measured between crude oil and carbonate in the presence of polymer. These consistent results obtained from different experimental techniques indicated that the oil recovery improvements observed with polymer in dynamic liberation tests are not only related to the increase in water viscosity but are also due to favorable changes in wettability as inferred from both contact angle and adhesion force measurements. This experimental study, for the first time, characterized the microscale effects of polymer on wettability alteration and crude oil liberation in carbonates. The favorable effect of polymer on wettability alteration in carbonates revealed from this study has not been reported in the literature, and it can become a novel addition to the existing knowledge.

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Role of divalent ions, temperature, and crude oil during water injection into dolomitic carbonate oil reservoirs

Oil & Gas Science and Technology – Revue d’IFP Energies nouvelles ◽

10.2516/ogst/2019003 ◽

2019 ◽

Vol 74 ◽

pp. 36 ◽

Cited By ~ 1

Author(s):

Mohammad Fattahi Mehraban ◽

Shahab Ayatollahi ◽

Mohammad Sharifi

Keyword(s):

Contact Angle ◽

Crude Oil ◽

Oil Recovery ◽

Elevated Temperatures ◽

Angle Measurement ◽

Wettability Alteration ◽

Effect Of Temperature ◽

Surface Charges ◽

Potential Measurement ◽

Asphaltene Content

Although wettability alteration has been shown to be the main control mechanism of Low Salinity and Smart Water (LS-SmW) injection, our understanding of the phenomena resulting in wettability changes still remains incomplete. In this study, more attention is given to direct measurement of wettability through contact angle measurement at ambient and elevated temperatures (28 °C and 90 °C) during LS-SmW injection to identify trends in wettability alteration. Zeta potential measurement is utilized as an indirect technique for wettability assessment in rock/brine and oil/brine interfaces in order to validate the contact angle measurements. The results presented here bring a new understanding to the effect of temperature and different ions on the wettability state of dolomite particles during an enhanced oil recovery process. Our observations show that increasing temperature from 28 °C to 90 °C reduces the contact angle of oil droplets from 140 to 41 degrees when Seawater (SW) is injected. Besides, changing crude oil from crude-A (low asphaltene content) to crude-B (high asphaltene content) contributes to more negative surface charges at the oil/brine interface. The results suggest that the sulphate ion (SO42-) is the most effective ion for altering dolomite surface properties, leading to less oil wetness. Our study also shows that wettability alteration at ambient and elevated temperatures during LS-SmW injection can be explained by Electrical Double Layer (EDL) theory.

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Mechanism of active silica nanofluids based on interface-regulated effect during spontaneous imbibition

Petroleum Science ◽

10.1007/s12182-020-00537-8 ◽

2021 ◽

Author(s):

Xu-Guang Song ◽

Ming-Wei Zhao ◽

Cai-Li Dai ◽

Xin-Ke Wang ◽

Wen-Jiao Lv

Keyword(s):

Contact Angle ◽

Interfacial Tension ◽

Oil Recovery ◽

Dynamic Contact Angle ◽

Liquid Interface ◽

Spontaneous Imbibition ◽

Wettability Alteration ◽

Low Permeability ◽

Oil Water ◽

Solid Liquid

AbstractThe ultra-low permeability reservoir is regarded as an important energy source for oil and gas resource development and is attracting more and more attention. In this work, the active silica nanofluids were prepared by modified active silica nanoparticles and surfactant BSSB-12. The dispersion stability tests showed that the hydraulic radius of nanofluids was 58.59 nm and the zeta potential was − 48.39 mV. The active nanofluids can simultaneously regulate liquid–liquid interface and solid–liquid interface. The nanofluids can reduce the oil/water interfacial tension (IFT) from 23.5 to 6.7 mN/m, and the oil/water/solid contact angle was altered from 42° to 145°. The spontaneous imbibition tests showed that the oil recovery of 0.1 wt% active nanofluids was 20.5% and 8.5% higher than that of 3 wt% NaCl solution and 0.1 wt% BSSB-12 solution. Finally, the effects of nanofluids on dynamic contact angle, dynamic interfacial tension and moduli were studied from the adsorption behavior of nanofluids at solid–liquid and liquid–liquid interface. The oil detaching and transporting are completed by synergistic effect of wettability alteration and interfacial tension reduction. The findings of this study can help in better understanding of active nanofluids for EOR in ultra-low permeability reservoirs.

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Evaluation of Nanofluids for Selected Malaysian Oilfields with Limited Cores: A Rapid Test Approach

10.2118/205561-ms ◽

2021 ◽

Author(s):

Luky Hendraningrat ◽

Saeed Majidaie ◽

Che Abdul Nasser Bakri Bin Che Mamat ◽

Norzafirah Binti Razali ◽

Chee Sheau Chien ◽

...

Keyword(s):

Contact Angle ◽

Oil Recovery ◽

Glass Plate ◽

Rapid Test ◽

Wettability Alteration ◽

Marginal Effect ◽

Screening Process ◽

Recovery Method ◽

Solid Media ◽

Research Period

Abstract As an emerging technology, nanoparticle offers advanced benefits to be used as a novel improved oil recovery method. The nanoparticle has a much smaller size than pores of rock that can penetrate deeper in the reservoir and it is easily functionalized to change the wettability of rocks. However, the synthesize and screening process of nanofluids will be a laborious task and need a long-term period and numerous cores at rock-fluid tests. It would be a big issue if the research period is short and native cores are limited or even unavailable. This paper presents a rapid test approach to evaluate nanofluids for a Malaysian oilfield with limited cores. Numerous nanofluids: nanopolymer and nanosurfactants, were evaluated using crude oil from a selected oilfield. Rapid measurement tests are proposed based on a parallel bottom-up approach from contact angle, thermal stability, and interfacial tension (IFT) measurement with at reservoir temperature conditions. Glass plate was initially used as the solid media for optimization of nanofluids concentration. Once this is ascertained then it can be used for further analysis on limited native core slab. Rock mineralogy, fluid rheology, and characterization were also determined. The fluid-fluid and rock-fluid measurements were repeated to ensure consistency of results and to estimate deviation in measurements. Based on a rapid test approach, it was observed that the screening process only took several days instead of months to select suitable nanofluids and glass plates that could be used in the screening process to reduce consuming cores for oilfields with a limited core. A series of glass plate experiment showed consistent results with the core slab. It was observed that dynamic optical contact angle using can achieve steady conditions for approximately half an hour. It was also observed that both the glass plate and replicate core slab show consistency of wettability alteration trend and benefits of multiple runs can observe how big the deviation of measurement. As predicted, all nanofluids can alter the rock wetting behavior. A decreasing contact angle showed that the solid media was rendered to be more water-wet, which implies better oil displacement due to residual oil saturation reduction. Surfactant grafted nanoparticles have given marginal effect on IFT reduction at a certain concentration and achieved steady in less than an hour. These results showed the most potential rapidly for further analysis on coreflooding experiments. The rapid test approach can evaluate and screen nanofluids for detailed coreflooding experiments. This approach readily applies for uncored or limited cores and limited research period.

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Experimental Study on Direct Current Voltage Assisted Carbonated Water-Flooding Mechanism in Tight Oil Reservoir

10.2523/iptc-21498-ms ◽

2021 ◽

Author(s):

Rukuan Chai ◽

Yuetian Liu ◽

Yuting He ◽

Qianjun Liu ◽

Wenhuan Gu

Keyword(s):

Crude Oil ◽

Direct Current ◽

Oil Recovery ◽

Co2 Sequestration ◽

Water Flooding ◽

Current Voltage ◽

Direct Current Voltage ◽

Carbonated Water ◽

Ft Icr Ms ◽

Ft Icr

Abstract Tight oil reservoir plays an increasingly important role in the world energy system, but its recovery is always so low. Hence, a more effective enhanced oil recovery (EOR) technology is urgently needed. Meanwhile, greenhouse effect is more and more serious, a more effective carbon capture and sequestration (CCS) method is also badly needed. Direct current voltage assisted carbonated water-flooding is a new technology that combines direct current voltage with carbonated water-flooding to enhance oil recovery and CO2 sequestration efficiency, simultaneously. Experimental studies were conducted from macroscopic-scale to microscopic-scale to study the performance and mechanism of direct current voltage assisted carbonated water-flooding. Firstly, core flood experiments were implemented to study the effect of direct current voltage assisted carbonated water on oil recovery and CO2 sequestration efficiency. Secondly, contact angle and interfacial tension/dilatational rheology were measured to analyze the effect of direct current voltage assisted carbonated water on crude oil-water-rock interaction. Thirdly, total organic carbon (TOC), gas chromatography (GC), and electrospray ionization-fourier transform ion cyclotron resonance-mass spectrometry (ESI FT ICR-MS) were used to investigate the organic composition change of produced effluents and crude oil in direct current voltage assisted carbonated water treatment. Through direct current voltage assisted carbonated water-flooding experiments, the following results can be obtained. Firstly, direct current voltage assisted carbonated waterflooding showed greater EOR capacity and CO2 sequestration efficiency than individual carbonated water and direct current voltage treatment. With the increase of direct current voltage, oil recovery increases to 38.67% at 1.6V/cm which much higher than 29.07% of carbonated water-flooding and then decreases, meanwhile, CO2 output decreases to only 35.5% at 1.6V/cm which much lower than 45.6% of carbonated water-flooding and then increases. Secondly, in direct current voltage assisted carbonated water-flooding, the wettability alteration is mainly caused by carbonated water and the effect of direct current can be neglected. While both carbonated water and direct current have evident influence on interfacial properties. Herein, with direct current voltage increasing, the interfacial tension firstly decreases and then increases, the interfacial viscoelasticity initially strengthens and then weakens. Thirdly, GC results indicated that crude oil cracking into lighter components occurs during direct current voltage assisted carbonated water-flooding, with the short-chain organic components increasing and the long-chain components decreasing. Meanwhile, TOC and ESI FT ICR-MS results illustrated that CO2 electroreduction do occur in direct current voltage assisted carbonated water-flooding with the dissolved organic molecules increases and the emergence of formic acid. Conclusively, the synergy of CO2 electrochemical reduction into formic acid in aqueous solution and the long-chain molecules electrostimulation pyrolysis into short ones in crude oil mutually resulted in the enhancement of crude oil-carbonated water interaction. This paper proposed a new EOR & CCS technology-direct current voltage assisted carbonated water-flooding. It showed great research and application potential on tight oil development and greenhouse gas control. More work needs to be done to further explore its mechanism. This paper constructs a multiscale & interdisciplinary research system to study the multidisciplinary (EOR&CCS) problem. Specifically, a series connected physical (Core displacement, Contact angle, and Interfacial tension/rheology measurements) and chemistry (TOC, GS, and ESI FT ICR-MS) experiments are combined to explore its regularity and several physics (Atomic physics) and chemistry (Electrochemistry/Inorganic Chemistry) theories are applied to explain its mechanisms.

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Geochemical Modeling on Effect of Active Species, Ca2+, Mg2+ and SO2-4 on the Carbonate Rock Surface, in Connection to Wettability Alteration of the Rock

10.2118/200829-ms ◽

2021 ◽

Author(s):

Mohamed Ibrahim Mohamed ◽

Vladimir Alvarado

Keyword(s):

Contact Angle ◽

Surface Charge ◽

Oil Recovery ◽

Carbonate Rock ◽

Carbonate Reservoirs ◽

Wettability Alteration ◽

Rock Properties ◽

Carboxyl Group ◽

Geochemical Model ◽

Positively Charged

Abstract A large percentage of petroleum reserves are located in carbonate reservoirs, which can be divided into limestone, chalk and dolomite. Roughly the oil recovery from carbonates is below the 30% due to the strong oil wetness, low permeability, abundance of natural fractures, and inhomogeneous rock properties Austad (2013). Injection of adjusted brine chemistry into carbonate reservoirs has been reported to increase oil recovery by 5-30% of the original oil in place in field tests and core flooding experiments. Previous studies have shown that adjusted waterflooding recovery in carbonate reservoirs is dependent on the composition and ionic strength of the injection brine (Morrow et al. 1998; Zhang 2005). Many research works have focused on the role of the brine composition in altering the initial wettability state of carbonate rock, which is usually intermediate- to oil-wet. Crude oils contain carboxyl group, -COOH, that can be found in the resin and asphaltenes fractions. The negatively charged carboxyl group, -COOH bond very strongly with the positively charged, sites on the carbonate surface. The carbonate surface, which is positively charged is believed to adsorb the SO42− that is negatively charged. On the other side cations Ca2+ and Mg2+ bind to the negatively charged carboxylic group and release it from the surface. In this study we use a closed system geochemical model to study the effect of the surface-charge dominant species; Ca2+, Mg2+ and SO42− on the carbonate surfaces at 80 °C. The proposed geochemical interactions can possibly lead to a change in the surface charge, altering wettability of the rock by exchanging ions/cations. Brines with various concentrations of Mg2+ and SO42− were prepared in the lab and contact angle between carbonate substrate and crude oil was measured using a rising/captive bubble tensiometer at 80 °C. The composition of the carbonate system was collected from previous literature review and the composition of adjusted brines was used to build a surface sorption database to develop a geochemical model. This model is focused on identifying the reaction paths and the surface behavior that may represent the real system. Changes in carbonate surface wettability were further evaluated using a series of contact angle experiments. Experimental observations and modeling results are concordant and imply that SO42− ions may alter the wettability of carbonate surface at high temperature.

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

SPE Journal ◽

10.2118/169127-pa ◽

2018 ◽

Vol 23 (03) ◽

pp. 803-818 ◽

Cited By ~ 24

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.

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

Biointerface Research in Applied Chemistry ◽

10.33263/briac105.63286342 ◽

2020 ◽

Vol 10 (5) ◽

pp. 6328-6342 ◽

Cited By ~ 1

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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Design and formulation of surfactant stabilized O/W emulsion for application in enhanced oil recovery: effect of pH, salinity and temperature

Oil & Gas Science and Technology – Revue d’IFP Energies nouvelles ◽

10.2516/ogst/2020066 ◽

2020 ◽

Vol 75 ◽

pp. 72

Author(s):

Narendra Kumar ◽

Saif Ali ◽

Amit Kumar ◽

Ajay Mandal

Keyword(s):

Crude Oil ◽

Experimental Model ◽

Enhanced Oil Recovery ◽

Droplet Size ◽

Oil Recovery ◽

Sodium Dodecyl ◽

Wettability Alteration ◽

Independent Variables ◽

Significant Difference ◽

Reservoir Conditions

Mobilization of crude oil from the subsurface porous media by emulsion injection is one of the Chemical Enhanced Oil Recovery (C-EOR) techniques. However, deterioration of emulsion by phase separation under harsh reservoir conditions like high salinity, acidic or alkaline nature and high temperature pose a challenge for the emulsion to be a successful EOR agent. Present study aims at formulation of Oil-in-Water (O/W) emulsion stabilized by Sodium Dodecyl Sulfate (SDS) using the optimum values of independent variables – salinity, pH and temperature. The influence of above parameters on the physiochemical properties of the emulsion such as average droplet size, zeta (ζ) potential, conductivity and rheological properties were investigated to optimize the properties. The influence of complex interactions of independent variables on emulsion characteristics were premeditated by experimental model obtained by Taguchi Orthogonal Array (TOA) method. Accuracy and significance of the experimental model was verified using Analysis Of Variance (ANOVA). Results indicated that the experimental models were significantly (p < 0.05) fitted with main influence of salinity (making it a critical variable) followed by its interactions with pH and temperature for all the responses studied for the emulsion properties. No significant difference between the predicted and experimental response values of emulsion ensured the adequacy of the experimental model. Formulated optimized emulsion manifested good stability with 2417.73 nm droplet size, −72.52 mV ζ-potential and a stable rheological (viscosity and viscoelastic) behavior at extensive temperature range. Ultralow Interfacial Tension (IFT) value of 2.22E-05 mN/m was obtained at the interface of crude oil and the emulsion. A favorable wettability alteration of rock from intermediate-wet to water-wet was revealed by contact angle measurement and an enhanced emulsification behavior with crude oil by miscibility test. A tertiary recovery of 21.03% of Original Oil In Place (OOIP) was obtained on sandstone core by optimized emulsion injection. Therefore, performance assessment of optimized emulsion under reservoir conditions confirms its capability as an effective oil-displacing agent.

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Glycine for Enhanced Water Imbibition in Carbonate Reservoirs – What is the Role of Amino Group?

10.2118/206294-ms ◽

2021 ◽

Author(s):

Ilgar Baghishov ◽

Gayan A. Abeykoon ◽

Mingyuan Wang ◽

Francisco J. Argüelles Vivas ◽

Ryosuke Okuno

Keyword(s):

Contact Angle ◽

Oil Recovery ◽

Wettability Alteration ◽

Carboxyl Group ◽

Amino Group ◽

Acetate Solution ◽

Calcite Dissolution ◽

Water Imbibition ◽

Glycine Solution ◽

Formate Solution

Abstract Previous studies indicated the efficacy of the simplest amino acid, glycine, as an aqueous additive for enhanced water imbibition in carbonate reservoirs. The objective of this research was to investigate the importance of the amino group of glycine in its enhanced water imbibition. To this end, glycine was compared with two carboxylates (acetate and formate) with/without adding hydrogen chloride (HCl) for adjusting the solution pH. Note that the amino group is the only difference between glycine and acetate. Contact-angle experiments on calcite were carried out at 347 K and atmospheric pressure with 68000-ppm reservoir brine (RB), and 4 different concentrations of glycine, acetate, and formate solutions in RB. To test the hypothesis that calcite dissolution is one of the main mechanisms in wettability alteration by glycine, we performed another set of contact angle experiments by adding HCl to brine, acetate, and formate solutions. HCl was added to match the pH of the glycine solution at the same concentration. We also performed imbibition tests with Texas Cream Limestone cores at 347 K with brine, glycine, acetate, and formate solutions (with and without HCl) in RB at 5.0 wt%. Contact-angle results indicated that glycine changed calcite's wettability from oil-wet to water-wet (45°). However, acetate solution was not able to change the wettability to water-wet; and formate moderately decreased the contact angle to 80°. The pH level increased from 6.1 to 7.6 after the contact angle experiment in glycine solution, indicating the consumption of hydrogen ions due to calcite dissolution. The levels of pH in formate and acetate solutions, however, decreased from 8.4 to 7.8. The acidity of glycine above its isoelectric point arises from the deprotonation of the carboxyl group. Imbibition tests with carbonate cores supported the observations from the contact-angle experiments. The oil recovery was 31% for glycine solution, 20% for RB, 21% for formate solution, and 19% for acetate solution. This re-confirmed the effectiveness of glycine as an additive to improve the oil recovery from carbonates. An additional set of imbibition tests revealed that acetate at the pH reduced to the same level as glycine was still not able to recover as much oil as glycine. This showed that glycine recovered oil not only because of the calcite dissolution and the carboxyl group, but also because of the amino group. It is hypothesized that the amino group with its electron donor ability creates a chelation effect that makes glycine entropically more favorable to get attached to the calcite surface than acetate. Another important result is that the formate solution at an adjusted pH resulted in a greater oil recovery than RB or RB at the same pH. This indicates that there is an optimal pH for the carboxyl group to be effective in wettability alteration as also indicated by the pH change during the contact-angle experiment.

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