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

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.

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

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.

scholarly journals Wettability Alteration in High-Temperature and High-Salinity Carbonate Reservoirs

SPE Journal ◽  
2013 ◽  
Vol 18 (04) ◽  
pp. 646-655 ◽  
Author(s):  
Gaurav Sharma ◽  
Kishore K. Mohanty
Keyword(s):  
Contact Angle ◽  
High Temperature ◽  
Oil Recovery ◽  
Carbonate Rock ◽  
High Salinity ◽  
Spontaneous Imbibition ◽  
Wettability Alteration ◽  
Surfactant Systems ◽  
Original Oil In Place ◽  
Harsh Conditions

Summary The goal of this work was to change the wettability of a carbonate rock from mixed-wet toward water-wet at high temperature and high salinity. Three types of surfactants in dilute concentrations (<0.2 wt%) were used. Initial surfactant screening was performed on the basis of aqueous stability at these harsh conditions. Contact-angle experiments on aged calcite plates were conducted to narrow the list of surfactants, and spontaneous-imbibition experiments were conducted on field cores for promising surfactants. Secondary waterflooding was carried out in cores with and without the wettability-altering surfactants. It was observed that most but not all surfactants were aqueous-unstable by themselves at these harsh conditions. Dual-surfactant systems, mixtures of a nonionic and a cationic surfactant, increased the aqueous stability. Some of the dual-surfactant systems proved effective for wettability alteration and could recover could recover 70 to 80% OOIP (original oil in place) during spontaneous imbibition. Secondary waterflooding with the wettability-altering surfactant increased the oil recovery over the waterflooding without the surfactants (from 29 to 40% of OOIP).

scholarly journals Wettability alteration and oil recovery by spontaneous imbibition of smart water and surfactants into carbonates

2020 ◽  
Vol 17 (3) ◽  
pp. 712-721 ◽  
Author(s):  
Saeb Ahmadi ◽  
Mostafa Hosseini ◽  
Ebrahim Tangestani ◽  
Seyyed Ebrahim Mousavi ◽  
Mohammad Niazi
Keyword(s):  
Contact Angle ◽  
Enhanced Oil Recovery ◽  
Oil Recovery ◽  
Carbonate Rock ◽  
Spontaneous Imbibition ◽  
Wettability Alteration ◽  
Rock Surface ◽  
Smart Water ◽  
Fractured Carbonate ◽  
Enhance Oil Recovery

AbstractNaturally fractured carbonate reservoirs have very low oil recovery efficiency owing to their wettability and tightness of matrix. However, smart water can enhance oil recovery by changing the wettability of the carbonate rock surface from oil-wet to water-wet, and the addition of surfactants can also change surface wettability. In the present study, the effects of a solution of modified seawater with some surfactants, namely C12TAB, SDS, and TritonX-100 (TX-100), on the wettability of carbonate rock were investigated through contact angle measurements. Oil recovery was studied using spontaneous imbibition tests at 25, 70, and 90 °C, followed by thermal gravity analysis to measure the amount of adsorbed material on the carbonate surface. The results indicated that Ca2+, Mg2+, and SO42− ions may alter the carbonate rock wettability from oil-wet to water-wet, with further water wettability obtained at higher concentrations of the ions in modified seawater. Removal of NaCl from the imbibing fluid resulted in a reduced contact angle and significantly enhanced oil recovery. Low oil recoveries were obtained with modified seawater at 25 and 70 °C, but once the temperature was increased to 90 °C, the oil recovery in the spontaneous imbibition experiment increased dramatically. Application of smart water with C12TAB surfactant at 0.1 wt% changed the contact angle from 161° to 52° and enhanced oil recovery to 72%, while the presence of the anionic surfactant SDS at 0.1 wt% in the smart water increased oil recovery to 64.5%. The TGA analysis results indicated that the adsorbed materials on the carbonate surface were minimal for the solution containing seawater with C12TAB at 0.1 wt% (SW + CTAB (0.1 wt%)). Based on the experimental results, a mechanism was proposed for wettability alteration of carbonate rocks using smart water with SDS and C12TAB surfactants.

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

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.

A Novel Coreflood Test to Evaluate EOR Potential of Wettability-Altering Surfactants in Oil-Wet Heterogeneous Carbonate Reservoirs

2021 ◽  
Author(s):  
Yue Shi ◽  
Kishore Mohanty ◽  
Manmath Panda
Keyword(s):  
Oil Recovery ◽  
Carbonate Reservoirs ◽  
Wettability Alteration ◽  
Low Permeability ◽  
High Permeability ◽  
Matrix Permeability ◽  
Rock Heterogeneity ◽  
The Matrix ◽  
Flow Through ◽  
Main Factors

Abstract Oil-wetness and heterogeneity (i.e., existence of low and high permeability regions) are two main factors that result in low oil recovery by waterflood in carbonate reservoirs. The injected water is likely to flow through high permeability regions and bypass the oil in low permeability matrix. In this study, systematic coreflood tests were carried out in both "homogeneous" cores and "heterogeneous" cores. The heterogeneous coreflood test was proposed to model the heterogeneity of carbonate reservoirs, bypassing in low-permeability matrix during waterfloods, and dynamic imbibition of surfactant into the low-permeability matrix. The results of homogeneous coreflood tests showed that both secondary-waterflood and secondary-surfactant flood can achieve high oil recovery (>50%) from relatively homogenous cores. A shut-in phase after the surfactant injection resulted in an additional oil recovery, which suggests enough time should be allowed while using surfactants for wettability alteration. The core with a higher extent of heterogeneity produced lower oil recovery to waterflood in the coreflood tests. Final oil recovery from the matrix depends on matrix permeability as well as the rock heterogeneity. The results of heterogeneous coreflood tests showed that a slow surfactant injection (dynamic imbibition) can significantly improve the oil recovery if the oil-wet reservoir is not well-swept.

Effect and Mechanism of CO2 Electrochemical Reduction for CCUS-EOR

2021 ◽  
Author(s):  
Rukaun Chai ◽  
Yuetian Liu ◽  
Qianjun Liu ◽  
Xuan He ◽  
Pingtian Fan
Keyword(s):  
Contact Angle ◽  
Crude Oil ◽  
Electrochemical Reduction ◽  
1H Nmr ◽  
Oil Recovery ◽  
Co2 Sequestration ◽  
Sno2 Nanoparticles ◽  
Wettability Alteration ◽  
X Ray ◽  
Electrochemical Conversion

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.

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

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.

The effect of surfactant concentration on nanoparticles surface wettability during wettability alteration of oil-wet carbonate rock

2021 ◽  
Vol 15 (2) ◽  
pp. 7993-8002
Author(s):  
Wan Mohd Shaharizuan Mat Latif ◽  
M. S. M. Musa ◽  
A.S.M. Balakirisnan ◽  
W. R. W. Sulaiman
Keyword(s):  
Contact Angle ◽  
Silicon Dioxide ◽  
Carbonate Rock ◽  
Surfactant Concentration ◽  
Sodium Dodecyl ◽  
Particle Surface ◽  
Surface Wettability ◽  
Wettability Alteration ◽  
Inverse Effect ◽  
Sds Surfactant

Previous studies reported that the presence of surfactant increases nanoparticles surface wettability by in-situ surface activation. On the other hand, the excess of surfactant concentration has an inverse effect on particle hydrophobicity by altering it to be hydrophilic back. Hence, this study presents an experimental investigation of wettability alteration by using a surfactant-nanoparticles system by using cetyltrimethylammonium bromide (CTAB) and sodium dodecyl sulfate (SDS) surfactant, and hydrophilic silicon dioxide (SiO2) and partially hydrophobic silicon dioxide (PH SiO2) nanoparticles. The nanoparticles surface wettability and the wettability alteration of oil-wet carbonate rock were measured by using the contact angle method. The result shows that the contact angle of the oil-wet carbonate rock was most reduced by using CTAB-hydrophilic SiO2, from 112.00o to 28.35o. The excess of surfactant concentration (beyond CMC) shows an inverse effect on particle surface wettability, however, induces the water-wetness of the carbonate rock. Besides, the hydrophilic SiO2 shows a more effective effect as a wettability modifier than the PH SiO2, in the absence and presence of CTAB or SDS surfactant.

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