Oil/water/rock wettability: Influencing factors and implications for low salinity water flooding in carbonate reservoirs

Chen, Yongqiang; Xie, Quan; Sari, Ahmad; Brady, Patrick V.; Saeedi, Ali

doi:10.1016/j.fuel.2017.10.031

Oil/water/rock wettability: Influencing factors and implications for low salinity water flooding in carbonate reservoirs

Journal Article · Tue Nov 21 00:00:00 EST 2017 · Fuel

DOI:https://doi.org/10.1016/j.fuel.2017.10.031· OSTI ID:1421633

^[1]; ^[1]; Sari, Ahmad ^[2]; Brady, Patrick V. ^[3]; Saeedi, Ali ^[2]

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.

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Research Organization:: Curtin Univ., Kensington, WA (Australia); Sandia National Lab. (SNL-NM), Albuquerque, NM (United States); Southwest Petroleum Univ., Chengdu (China)

Sponsoring Organization:: Southwest Petroleum Univ. (China); USDOE National Nuclear Security Administration (NNSA)

Grant/Contract Number:: NA0003525

OSTI ID:: 1421633

Report Number(s):: SAND2017--13621J; PII: S0016236117312747

Journal Information:: Fuel, Journal Name: Fuel Vol. 215; ISSN 0016-2361

Publisher:: ElsevierCopyright Statement

Country of Publication:: United States

Language:: English

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An overview of the oil-brine interfacial behavior and a new surface complexation model Bonto, María; Eftekhari, Ali A.; Nick, Hamidreza M. Scientific Reports, Vol. 9, Issue 1 https://doi.org/10.1038/s41598-019-42505-2	journal	April 2019
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Effect of SO ₄ ⁻² ion exchanges and initial water saturation on low salinity water flooding (LSWF) in the dolomite reservoir rocks Safavi, Mir Saeid; Masihi, Mohsen; Safekordi, Ali Akbar Journal of Dispersion Science and Technology, Vol. 41, Issue 6 https://doi.org/10.1080/01932691.2019.1614026	journal	May 2019
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