Low Salinity Oil Recovery: An Exciting New EOR Opportunity for Alaska's North Slope

McGuire, P.L.; Chatham, J.R.; Paskvan, F.; Sommer, Danny; Carini, F.

doi:10.2118/93903-ms

Cited by 522 publications

(249 citation statements)

References 18 publications

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“…As a conclusion based on many studies in this area, low salinity water improves oil recovery in both spontaneous imbibition and core flooding tests. Furthermore, oil recovery would be increased by increasing the dilution ratio (Kulathu et al 2013;McGuire et al 2005;Patil et al 2008;Shaddel and Tabatabae-Nejad 2015;Shaddel et al 2014;Shaker Shiran and Skauge 2013;Torrijos et al 2016;Wickramathilaka et al 2011). It should be noted that no impact on oil recovery was observed in experiments with zero salinity content.…”

Section: Introductionmentioning

confidence: 98%

“…The effect of sea water dilution ratio was investigated by measuring the recovered oil from Amott cells. In addition, mechanisms such as pH (McGuire et al 2005), multi-component ion exchange (Lager et al 2008b) and salting in (Rezaeidoust et al 2009) were evaluated throughout this study by measuring the experimental data before and after each experiment. Furthermore, the effects of temperature, core permeability and connate water were also investigated by analyzing the recovery curves of designed experiments.…”

Section: Introductionmentioning

confidence: 99%

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

et al. 2018

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An experimental study was performed to investigate the impact of low salinity water on wettability alteration in carbonate core samples from southern Iranian reservoirs by spontaneous imbibition. In this paper, the effect of temperature, salinity, permeability and connate water were investigated by comparing the produced hydrocarbon curves. Contact angle measurements were taken to confirm the alteration of surface wettability of porous media. Oil recovery was enhanced by increasing the dilution ratio of sea water, and there existed an optimum dilution ratio at which the highest oil recovery was achieved. In addition, temperature had a very significant impact on oil recovery from carbonate rocks. Furthermore, oil recovery from a spontaneous imbibition process was directly proportional to the permeability of the core samples. The presence of connate water saturation inside the porous media facilitated oil production significantly. Also, the oil recovery from porous media was highly dependent on ion repulsion/attraction activity of the rock surface which directly impacts on the wettability conditions. Finally, the highest ion attraction percentage was measured for sodium while there was no significant change in pH for all experiments.

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Section: Introductionmentioning

confidence: 98%

Section: Introductionmentioning

confidence: 99%

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

et al. 2018

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“…Several possible proposed mechanisms include (1) multicomponent ion 1 3 exchange (Lager et al 2008a, b), (2) double-layer expansion (Ligthelm et al 2009), (3) reduction in interfacial tension and increased pH (McGuire et al 2005), (4) fines mobilization (Tang and Morrow 1999), (5) mineral dissolution (Aksulu et al 2012), (6) organic material desorption from the clay surface ), (7) salt-in effect (RezaeiDoust et al 2009). However, the presence of clays in the porous media has proven to greatly impact production (Tang and Morrow 1999;Lager et al 2008a, b).…”

Section: Introductionmentioning

confidence: 99%

Sequential injection mode of high-salinity/low-salinity water in sandstone reservoirs: oil recovery and surface reactivity tests

Al-Saedi

Alhuraishawy

Flori

et al. 2018

J Petrol Explor Prod Technol

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The aim of this paper is to quantify the effect of low-salinity (LS) water on oil recovery from sandstone cores at different temperatures and at various permeabilities, oil viscosities, and Ca 2+ concentrations in the formation water. Six sandstone cores were waterflooded with high-salinity (HS) and LS water at various temperatures ranging from 25 to 90 °C. Four cores were allocated to oil recovery experiments, and the other two were dedicated to surface reactivity tests. The S wi and S or of the cores were established, and then the cores were pre-aged for 3 days at 70 °C with oil in a closed container. We examined the effect of different ionic solutions (HS water, LS water, and double Ca 2+ HS water) at different temperatures. The surface reactivity test cores were flooded with the same HS and LS brines that were used in oil recovery forced-imbibition experiments. During flooding, samples of the effluent were analyzed for pH and Ca 2+ . The absence of an oil phase enabled us to isolate and quantify the important water-rock reactions. Ca 2+ desorption from the core that was aged in the double Ca 2+ concentration was larger than that desorbed from the other core, but pH and pressure was less than the other core during surface reactivity tests. Due to dehydration at high temperatures, the desorption of Ca 2+ decreased as the temperature increased. Also, as the temperature increased, the pH gradient between the HS and LS water effluents decreased. Oil recovery forcedimbibition experiments with a double Ca 2+ concentration showed a small LS water effect at all temperatures, meaning that the cores became more water-wet; however, the LS water effect was much greater when the amount of Ca 2+ in the HS water was decreased by half. Furthermore, as the core permeability and oil viscosity increased, our tests showed a greater positive effect from the LS water. This work attempts to isolate the separate effects and thus examines the oil recovery achieved with the most important LS waterflood factors, which are temperature, ion exchange, and pH.

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“…of a wellbore (Webb et al 2004). McGuire et al (2005) presented results of four sets of single well chemical-tracer tests (SWCTT) within a radius of 13 to 14 ft around a wellbore in the Alaskan North Slope reservoir. Residual oil saturation was substantially reduced by 5-13% of OOIP by using LSW after high-salinity waterflooding.…”

Section: Literaturementioning

confidence: 99%

Reservoir Connate Water Chemical Composition Variations Effect on Low-Salinity Waterflooding

Shehata

Nasr‐El‐Din

2014

Abu Dhabi International Petroleum Exhibition and Conference

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Extensive experimental work has indicated that Low-Salinity Waterflooding (LSW) is an enhanced oil recovery technique that improves oil recovery by lowering and optimizing the salinity of that injected water. Most of the LSW studies focused on the injection of brine salinity and composition. The question remains how does the salinity and composition of reservoir connate water affects the LSW performance. Therefore, in this paper different connate water compositions were used (TDS varies from 1550 up to 174156 ppm) to investigate the role of reservoir connate water on the performance of LSW.Nine Spontaneous Imbibition (SI) experiments and six coreflood experiments were performed. Two sandstone types (Bandera and Buff Berea) with different clays contents and stock-tank crude oil samples were used in all the experiments. This work describes experimental studies of SI of oil by low-salinity and high salinity brines using 20Љ long outcrop sandstone samples. This study focused on the effect of connate water composition and temperature, 77 and 160°F, on the performance of LSW. The coreflood experiments have been conducted using 6 in. outcrop Buff Berea sandstone cores at 150°F and 500 psi. Oil recovery and pressure drop were observed and analyzed after each coreflooding experiment to examine the effect of the connate water composition (Na ϩ , Ca ϩ2 , and Mg ϩ2 ) on the performance of the LSW in secondary recovery mode.Reservoir connate water composition and salinity have a dominant influence on the oil recovery rate. The Ca 2ϩ , Mg 2ϩ , and Na ϩ ions play a key role in oil mobilization in different sandstone rocks. Reservoir cores saturated with connate water contained divalent cations of Ca ϩ2 and Mg ϩ2 showed higher oil recovery for cores saturated with monovalent cations Na ϩ . Low-salinity waterflooding showed a high potential to improve oil recovery in the SI experiments at different temperature levels. For high permeability Buff Berea cores, the SI oil recovery ranged from 38 to 69% OOIP, while oil recovery of the low permeability Bandera cores ranged from 17 to 45% OOIP at 77°F and 14.7 psia. As the temperature increased from 77 to 160°F, an additional oil recovery up to 4.2% of OOIP was observed by SI for Buff Berea cores. From the coreflood experiments, low-salinity brine had a significant positive effect on oil recovery for sandstone cores saturated with divalent cations (Ca ϩ2 and Mg ϩ2 ). The magnitude of incremental oil recovery increased from 51.9 to 58.9% OOIP when the reservoir connate water salinity increased from 3,420 to 36,350 ppm. On the other hand, increasing the monovalent cations (Na ϩ ) from 1,550 to 137,670 ppm resulted in slight increase in oil recovery (1.2% OOIP). The oil recovery from the coreflood runs for the Buff Berea cores ranged from 58.9 to 35.9% OOIP. The oil recovery decreased when the salinity of reservoir connate water decreased.

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Low Salinity Oil Recovery: An Exciting New EOR Opportunity for Alaska's North Slope

Cited by 522 publications

References 18 publications

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

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

Sequential injection mode of high-salinity/low-salinity water in sandstone reservoirs: oil recovery and surface reactivity tests

Reservoir Connate Water Chemical Composition Variations Effect on Low-Salinity Waterflooding

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