Oil/water/rock wettability: Influencing factors and implications for low salinity water flooding in carbonate reservoirs
[1];
[1];
- Curtin Univ., Kensington, WA (Australia). Dept. of Petroleum Engineering; Southwest Petroleum Univ., Chengdu (China). State Key Lab. of Oil and Gas Reservoir Geology and Exploitation
- Curtin Univ., Kensington, WA (Australia). Dept. of Petroleum Engineering
- Sandia National Lab. (SNL-NM), Albuquerque, NM (United States)
Wettability of the oil/brine/rock system is an essential petro-physical parameter which governs subsurface multiphase flow behaviour and the distribution of fluids, thus directly affecting oil recovery. Recent studies [1–3] show that manipulation of injected brine composition can enhance oil recovery by shifting wettability from oil-wet to water-wet. However, what factor(s) control system wettability has not been completely elucidated due to incomplete understanding of the geochemical system. To isolate and identify the key factors at play we used in this paper SO42—free solutions to examine the effect of salinity (formation brine/FB, 10 times diluted formation brine/10 dFB, and 100 times diluted formation brine/100 dFB) on the contact angle of oil droplets at the surface of calcite. We then compared contact angle results with predictions of surface complexation by low salinity water using PHREEQC software. We demonstrate that the conventional dilution approach likely triggers an oil-wet system at low pH, which may explain why the low salinity water EOR-effect is not always observed by injecting low salinity water in carbonated reservoirs. pH plays a fundamental role in the surface chemistry of oil/brine interfaces, and wettability. Our contact angle results show that formation brine triggered a strong water-wet system (35°) at pH 2.55, yet 100 times diluted formation brine led to a strongly oil-wet system (contact angle = 175°) at pH 5.68. Surface complexation modelling correctly predicted the wettability trend with salinity; the bond product sum ([>CaOH2+][–COO-] + [>CO3-][–NH+] + [>CO3-][–COOCa+]) increased with decreasing salinity. Finally, at pH < 6 dilution likely makes the calcite surface oil-wet, particularly for crude oils with high base number. Yet, dilution probably causes water wetness at pH > 7 for crude oils with high acid number.
- Research Organization:
- Sandia National Lab. (SNL-NM), Albuquerque, NM (United States); Southwest Petroleum Univ., Chengdu (China); Curtin Univ., Kensington, WA (Australia)
- Sponsoring Organization:
- USDOE National Nuclear Security Administration (NNSA); Southwest Petroleum Univ. (China)
- Grant/Contract Number:
- NA0003525; PLN201603
- OSTI ID:
- 1421633
- Report Number(s):
- SAND2017-13621J; PII: S0016236117312747
- Journal Information:
- Fuel, Vol. 215; ISSN 0016-2361
- Publisher:
- ElsevierCopyright Statement
- Country of Publication:
- United States
- Language:
- English
Web of Science
An overview of the oil-brine interfacial behavior and a new surface complexation model
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journal | April 2019 |
Smart water flooding performance in carbonate reservoirs: an experimental approach for tertiary oil recovery
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journal | April 2019 |
Response of Non-Polar Oil Component on Low Salinity Effect in Carbonate Reservoirs: Adhesion Force Measurement Using Atomic Force Microscopy
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journal | December 2019 |
Effect of SO 4 −2 ion exchanges and initial water saturation on low salinity water flooding (LSWF) in the dolomite reservoir rocks
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journal | May 2019 |
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