Effect of Total Acid Number and Recovery Mode on Low-Salinity Enhanced Oil Recovery in Carbonates

2021 ◽  
pp. 1-18
Author(s):  
Takaaki Uetani ◽  
Hiromi Kaido ◽  
Hideharu Yonebayashi
Keyword(s):  
Enhanced Oil Recovery ◽  
Oil Recovery ◽  
Carbonate Rock ◽  
Acid Number ◽  
Spontaneous Imbibition ◽  
Wettability Alteration ◽  
Oil Composition ◽  
Total Acid ◽  
Low Salinity ◽  
Total Acid Number

Summary Low-salinity water (LSW) flooding is an attractive enhanced oil recovery (EOR) option, but its mechanism leading to EOR is poorly understood, especially in carbonate rock. In this paper, we investigate the main reason behind two tertiary LSW coreflood tests that failed to demonstrate promising EOR response in reservoir carbonate rock; additional oil recovery factors by the LSW injection were only +2% and +4% oil initially in place. We suspected either the oil composition (lack of acid content) or the recovery mode (tertiary mode) was inappropriate. Therefore, we repeated the experiments using an acid-enriched oil sample and injected LSW in the secondary mode. The result showed that the low-salinity effect was substantially enhanced; the additional oil recovery factor by the tertiary LSW injection jumped to +23%. Moreover, it was also found that the secondary LSW injection was more efficient than the tertiary LSW injection, especially in the acid-enriched oil reservoir. In summary, it was concluded that the total acid number (TAN) and the recovery mode appear to be the key successful factors for LSW in our carbonate system. To support the conclusion, we also performed contact angle measurement and spontaneous imbibition tests to investigate the influence of acid enrichment on wettability, and moreover, LSW injection on wettability alteration.

scholarly journals Variations in Wettability and Interfacial Tension during Alkali–Polymer Application for High and Low TAN Oils

Polymers ◽  
2020 ◽  
Vol 12 (10) ◽  
pp. 2241
Author(s):  
Vladislav Arekhov ◽  
Rafael E. Hincapie ◽  
Torsten Clemens ◽  
Muhammad Tahir
Keyword(s):  
Interfacial Tension ◽  
Oil Recovery ◽  
Acid Number ◽  
Spontaneous Imbibition ◽  
Wettability Alteration ◽  
Rock Surface ◽  
Chemical Agent ◽  
Aging Effects ◽  
Divalent Ions ◽  
Total Acid

The injection of chemicals into sandstones can lead to alterations in wettability, where oil characteristics such as the TAN (total acid number) may determine the wetting state of the reservoir. By combining the spontaneous imbibition principle and the evaluation of interfacial tension index, we propose a workflow and comprehensive assessment to evaluate the wettability alteration and interfacial tension (IFT) when injecting chemical-enhanced oil-recovery (EOR) agents. This study examines the effects on wettability alteration due to the application of alkaline and polymer solutions (separately) and the combined alkali–polymer solution. The evaluation focused on comparing the effects of chemical agent injections on wettability and IFT due to core aging (non-aged, water-wet and aged, and neutral to oil-wet), brine composition (mono vs. divalent ions); core mineralogy (~2.5% and ~10% clay), and crude oil type (low and high TAN). Amott experiments were performed on cleaned water-wet core plugs as well as on samples with a restored oil-wet state. IFT experiments were compared for a duration of 300 min. Data were gathered from 48 Amott imbibition experiments with duplicates. The IFT and baselines were defined in each case for brine, polymer, and alkali for each set of experiments. When focusing on the TAN and aging effects, it was observed that in all cases, the early time production was slower and the final oil recovery was longer when compared to the values for non-aged core plugs. These data confirm the change in rock surface wettability towards a more oil-wet state after aging and reverse the wettability alteration due to chemical injections. Furthermore, the application of alkali with high TAN oil resulted in a low equilibrium IFT. By contrast, alkali alone failed to mobilize trapped low TAN oil but caused wettability alteration and a neutral–wet state of the aged core plugs. For the brine composition, the presence of divalent ions promoted water-wetness of the non-aged core plugs and oil-wetness of the aged core plugs. Divalent ions act as bridges between the mineral surface and polar compound of the in situ created surfactant, thereby accelerating wettability alteration. Finally, for mineralogy effects, the high clay content core plugs were shown to be more oil-wet even without aging. Following aging, a strongly oil-wet behavior was exhibited. The alkali–polymer is demonstrated to be efficient in the wettability alteration of oil-wet core plugs towards a water-wet state.

Osmosis as Mechanism for Low-Salinity Enhanced Oil Recovery

SPE Journal ◽  
2016 ◽  
Vol 21 (04) ◽  
pp. 1227-1235 ◽  
Author(s):  
K.. Sandengen ◽  
A.. Kristoffersen ◽  
K.. Melhuus ◽  
L. O. Jøsang
Keyword(s):  
Enhanced Oil Recovery ◽  
Oil Recovery ◽  
Salinity Gradient ◽  
Spontaneous Imbibition ◽  
Model Systems ◽  
Wettability Alteration ◽  
Connate Water ◽  
Low Salinity ◽  
Low Salinity Water ◽  
Salinity Water

Summary We believe that osmosis has been overlooked as a possible mechanism for observed low-salinity enhanced-oil-recovery (EOR) effects. Osmosis can occur in an oil/water/rock system when injecting low-salinity water, because the system is full of an excellent semipermeable membrane—the oil itself. In the present work, water transport through oil films was visualized both in 2D micromodels and in sandstone cores imaged in a microcomputed tomography (CT). After treating these model systems with hexamethyldisilazane (HMDS) to render them more oil-wet, water became discontinuous, and it was possible to establish osmotic gradients. Either expansion or contraction of the connate water was observed, depending on the direction of the imposed salinity gradient. Because osmosis could be the underlying mechanism for low-salinity EOR, two changes in research strategy are proposed: Most importantly, the use of spontaneous-imbibition tests as evidence for wettability alteration in low-salinity water should be critically reinvestigated. This is because observed production could have stemmed from “osmotic expansion” of the connate water rather than wettability change. Second, much research focus should be shifted from sandstone reservoirs to fractured oil-wet carbonates. Osmosis potentially yields larger responses for the latter reservoir type, whereas from a mechanistic perspective the reason behind low-salinity EOR functioning in both sandstones and carbonates deserves further attention.

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 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.

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.

NMR WETTABILITY INDEX MEASUREMENTS AND METHODS COMPARED ON A VARIETY OF UNCONVENTIONAL SAMPLES

2021 ◽  
Author(s):  
Shaina Kelly ◽  
◽  
Ron J.M. Bonnie ◽  
Micheal J. Dick ◽  
Dragan Veselinovic ◽  
...  
Keyword(s):  
Enhanced Oil Recovery ◽  
Oil Recovery ◽  
Critical Factor ◽  
Time Lapse ◽  
Spontaneous Imbibition ◽  
Wettability Alteration ◽  
Rock Properties ◽  
Full Spectrum ◽  
Mixing Ratios ◽  
Rock Types

Matrix wettability is a key driver in relative permeability and, hence, a critical factor controlling imbibition and drainage at UR fracture-matrix interfaces as well as enhanced oil recovery (EOR). In this study, we (1) adapt and apply the NMR-based wettability index (NWI) methodology of Looyestijn et al. (2006) to a variety of unconventional twin samples undergoing, respectively, spontaneous imbibition with oil-displacing-water and water-displacing-oil and (2) compare the robustness of this method among a variety of samples pairs and also to other NMR-based wettability methods. The samples analyzed cover a range of rock types, major formations, maturity and content of organic material. All displayed unique time-lapse wettability profiles and steady state NWI values. This work advances our previous works (Dick et al., 2019; Kelly et al., 2020) on this subject, where the viability of the methodology was established on end-member pilot samples, towards applicability as a UR SCAL method. The NWI methodology predicts T2 spectra using linear combinations (mixing) of “end-point” T2 spectra. The mixing ratios yielding the closest match to the measured spectra are then used to compute a wettability index. These mixing ratios were validated against (1) mass-balance calculations, (2) repeat experiments with heavy water (D2O) instead of H2O and (3) measured T1-T2 maps, enhancing confidence in the robustness of the method. Our comparisons show that alternative approaches representing the T2 spectra through a single mean T2 value or T2 peak-fit, fall short, especially in tight rocks where fast relaxation rate components tend to skew harmonic mean T2 values and also in samples where oil and water peaks are not clearly resolved. Full spectrum-based methods, akin to Looyestijn’s, appear more robust and stable over a much wider range of reservoir conditions. Repeated NMR acquisition throughout our long-term imbibition experiments shows that time-lapse NWI methodology probes the effects of rock properties, saturation changes, and injected fluid chemistry (enhanced oil recovery strategies) on wettability alteration. Additionally, this NWI study quantifies the wide variation in wettability among unconventional samples.

scholarly journals Enhanced oil recovery from carbonate reservoirs by spontaneous imbibition of low salinity water

2018 ◽  
Vol 15 (3) ◽  
pp. 564-576 ◽  
Author(s):  
Mohammad Reza Zaeri ◽  
Rohallah Hashemi ◽  
Hamidreza Shahverdi ◽  
Mehdi Sadeghi
Keyword(s):  
Enhanced Oil Recovery ◽  
Oil Recovery ◽  
Carbonate Reservoirs ◽  
Spontaneous Imbibition ◽  
Low Salinity ◽  
Low Salinity Water ◽  
Salinity Water
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