Chemical Verification of the EOR Mechanism by Using Low Saline/Smart Water in Sandstone

Rezaeidoust, Alireza; Puntervold, Tina; Austad, Tor

doi:10.1021/ef200215y

Cited by 186 publications

(193 citation statements)

References 19 publications

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“…It is documented that water chemistry significantly impacts the oil recovery factor (Morrow and Buckley 2011). In the past few years, many researchers have reported that the waterflooding recovery factor increased significantly by injecting high-salinity (HS) brine (seawater) into carbonate reservoirs (Strand et al 2008;Shariatpanahi et al 2010) and low-salinity brine into sandstone reservoirs (RezaeiDoust et al 2011). Wettability is one of the major parameters that control the efficiency of waterflooding.…”

Section: Introductionmentioning

confidence: 99%

“…However, the presence of clays in the porous media has proven to greatly impact production (Tang and Morrow 1999;Lager et al 2008a, b). In addition, the chemical composition of the injected water has proved to be another controlling parameter (RezaeiDoust et al 2009(RezaeiDoust et al , 2011Austad et al 2010). The control of mineralogy and water chemistry in oil recovery highlight the importance of considering simultaneous water-rock interactions, including mineral dissolution, desorption, and ion exchange during the low-salinity waterflooding of sandstone rocks.…”

Section: Introductionmentioning

confidence: 99%

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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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Section: Introductionmentioning

confidence: 99%

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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“…However, there is a pressing need to develop cost-effective techniques to enhance oil recovery in the period of low oil prices. Engineering the injected water chemistry and using water wisely to enhance oil recovery is a novel and emerging research area, which is called low salinity water flooding [4][5][6][7], smart water flooding [8][9][10][11][12], designer water flooding [13][14][15][16], or ion tuning water flooding [17,18]. Many researchers found that low salinity water injection could achieve an incredible additional oil recovery in sandstone and carbonate reservoirs from both experiments and field tests [19,20].…”

Section: Introductionmentioning

confidence: 99%

Effect of multi-component ions exchange on low salinity EOR: Coupled geochemical simulation study

2016

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The mechanism(s) of Low salinity water flooding (LSWF) has been extensively investigated for 15-20 years, as a cost-effective and environmentally friendly technique for improved oil recovery. However, there is still no consensus on the dominant mechanism(s) behind low salinity effect due to the complexity of interactions in the Crude oil/Brine/Rock (COBR) system. While wettability is most agreed mechanism of low salinity EOR effect. Nevertheless, the mechanism(s) behind the wettability change is debated between multi-component ion exchange (MIE) and double layer expansion (DLE) in sandstone reservoirs. This paper aims to investigate the effectiveness of MIE with a coupled geochemical-reservoir model using published experimental data reported by Nasralla and Nasr-El-We created core-scale numerical models with parameters identical to those used in the experiments. We simulated the low salinity effect using a commercial reservoir simulator, CMG-GEM, by coupling three chemical reactions: (1) aqueous reaction, (2) multi-component ion exchange, and (3) mineral dissolution and precipitation. We modelled the adsorption of divalent cations on the surface of the clay minerals during low salinity water injection. Simulation results were compared with the experimental results.Simulation results show that the fractional adsorption of divalent cations (Ca 2+ ) increased almost 25% by injecting a 2,000 ppm NaCl solution, compared to initial 10,000 ppm NaCl. Injecting a 2,000 ppm of CaCl 2 solution, however, significantly increased the adsorbed Ca 2+ from 0.1 to 1, which implies the complete saturation of mineral surface with divalent cations. Moreover, injecting 50,000 ppm of CaCl 2 solution also demonstrated the same effect as the 2,000 ppm CaCl 2 solution but with a faster rate.Upon combining the simulation and experimental results, we concluded that the multi-component ion exchange is not the sole mechanism behind low salinity effect for two reasons. First, almost 10% additional oil recovery was observed from the experiments by injecting the 2,000 ppm CaCl 2 compared with 50,000 ppm CaCl 2 solutions. Even though in both cases the surface is expected to be fully saturated with Ca 2+ according to the geochemical modelling. Second, 6% incremental oil recovery was achieved from the experiments by injecting 2,000 ppm NaCl solution compared with that of 50,000 ppm NaCl. Although 25% incremental adsorption of divalent cations (Ca 2+ ) were presented during the flooding of the 2,000 ppm NaCl solution. Therefore, it is worth noting that the electrical double layer expansion due to the ion exchange needs to be taken into account to pinpoint the mechanism(s) of low-salinity water effect.

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“…Therefore, we believe that injecting low salinity water or remove divalent cations from the hydraulic fracturing fluids likely causes a strong water-wet system, thus prevails water uptake due to capillary pressures acting as driving forces. In addition, note that low salinity water and softened brines (with absence of divalent cations) trigger a pH increase in a range of 1 to 3 due to ion exchange [21,37]. Thus, the bond product sum (Figure 8) would further decrease to exhibit a more water-wet system, favouring water uptake in shale reservoirs.…”

Section: Surface Complexation Modellingmentioning

confidence: 99%

Drivers of Wettability Alteration for Oil/Brine/Kaolinite System: Implications for Hydraulic Fracturing Fluids Uptake in Shale Rocks

et al. 2018

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Abstract:Hydraulic fracturing technique is of vital importance to effectively develop unconventional shale resources. However, the low recovery of hydraulic fracturing fluids appears to be the main challenge from both technical and environmental perspectives in the last decade. While capillary forces account for the low recovery of hydraulic fracturing fluids, the controlling factor(s) of contact angle, thus wettability, has yet to be clearly defined. We hypothesized that the interaction of oil/brine and brine/rock interfaces governs the wettability of system, which can be interpreted using Derjaguin-Landau-Verwey-Overbeek (DLVO) and surface complexation modelling. To test our hypothesis, we measured a suit of zeta potential of oil/brines and brine/minerals, and tested the effect of ion type (NaCl, MgCl 2 and CaCl 2 ) and concentrations (0.1, 1, and 5 wt %). Moreover, we calculated the disjoining pressure of the oil/brine/mineral systems and compared with geochemical modelling predictions. Our results show that cation type and salinity governed oil/brine/minerals wettability. Divalent cations (Ca 2+ and Mg 2+ ) compressed the electrical double layer, and electrostatically linked oil and clays, thus increasing the adhesion between oil and minerals, triggering an oil-wet system. Increasing salinity also compressed the double layer, and increased the site density of oppositely charged surface species which made oil and clay link more strongly. Our results suggest that increasing salinity and divalent cations concentration likely decrease water uptake in shale oil reservoirs, thus de-risking the hydraulic fracturing induced formation damage. Combining DLVO and surface complexation modelling can delineate the interaction of oil/brine/minerals, thus wettability. Therefore, the relative contribution of capillary forces with respect to water uptake into shale reservoirs, and the possible impairment of hydrocarbon production from conventional reservoirs can be quantified.

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Chemical Verification of the EOR Mechanism by Using Low Saline/Smart Water in Sandstone

Cited by 186 publications

References 19 publications

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

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

Effect of multi-component ions exchange on low salinity EOR: Coupled geochemical simulation study

Drivers of Wettability Alteration for Oil/Brine/Kaolinite System: Implications for Hydraulic Fracturing Fluids Uptake in Shale Rocks

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