Electrostatic Origins of CO2-Increased Hydrophilicity in Carbonate Reservoirs (original) (raw)
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Insights into the wettability alteration of CO2-assisted EOR in carbonate reservoirs
Journal of Molecular Liquids, 2019
Wettability of oil-brine-carbonate system is an important petro-physical parameter, which governs subsurface multiphase flow and residual oil saturation. CO 2-assisted EOR techniques have been identified as cost-effective and environmentally friendly means to unlock remaining hydrocarbon resources from carbonate reservoirs. While wettability alteration appears to be one of the main mechanisms during CO 2-assisted EOR implementation, the controlling factor(s) of wettability alteration at molecular level remains unclear. We thus hypothesized that excess of H + as a result of water uptake of CO 2 increases hydrophilicity of oil-brine-carbonate systems. More specifically, the surface charge properties will be alterated to more positive due to the increase of H + in the brine. To test this hypothesis, we measured oil contact angles on calcite surfaces in the presence of non-carbonated brine, carbonated brine, and acidic brine (pH = 3). We also performed surface complexation modelling to examine how the surface chemistry controls over wettability of oil/brine/carbonate system using PHREEQC. Our contact angle results show that both carbonated brine and acidic brine gave a contact angle of 24°and 22°, respectively, while non-carbonated brine gives a contact angle of 73°in 1 mol/L CaCl 2 brines. Same trend was also observed in synthesized formation brine, showing that non-carbonated formation brine yielded a contact angle of 69°while both acidic formation brine and carbonated formation brine gave a contact angle of 37°. Experimental results show that both carbonated brine, and acidic brine significantly decreased contact angle compared to non-carbonated brine, suggesting a strong water-wet system. Surface complexation modelling shows that for both carbonated water and acidic water, NCaOH 2 + dominates surface charges at calcite surfaces, and\ \NH + governs surface charges on oil surfaces. Together, these two processes increase repulsive forces thus hydrophilicity. Our study sheds light on the significant influence of excess H + due to water uptake of CO 2 on oil-brine-carbonate system wettability thus enhancing hydrocarbon recovery in carbonate reservoirs.
A pH-Resolved Wettability Alteration: Implications for CO2-Assisted EOR in Carbonate Reservoirs
Energy & Fuels, 2017
Wettability of oil/brine/rock system is a critical petro-physical parameter, which governs subsurface multiphase flow behavior, thus hydrocarbon recovery. While the mechanisms of CO2assisted enhanced oil recovery (EOR) techniques have been extensively investigated in carbonate reservoirs, few have done to identify the controlling factor of CO2-induced wettability alteration, and fewer have look beyond the implications for CO2-assisted EOR. We thus hypothesize that CO2-assisted EOR techniques cause a more hydrophilic system due to H + adsorption on the interface of oil/brine and brine/carbonate as a result of CO2 dissolution. To test this hypothesis, we measured contact angles of two oils with different acid and base number in the presence of 1M
Excess H+ Increases Hydrophilicity during CO2-Assisted Enhanced Oil Recovery in Sandstone Reservoirs
Energy & Fuels, 2019
10 CO 2-assisted enhanced oil recovery (EOR) appears to be a cost-effective and environmentally friendly 11 means to unlock remaining oil resources from sandstone reservoirs. While wettability alteration due 12 to water uptake of CO 2 has been identified as one of the primary mechanisms to govern subsurface 13 multiphase flow thus residual oil saturations, few work has been done to explore the leading factor of 14 wettability alteration, and fewer work has looked beyond the quantitative characterization of this 15 physical process. We hypothesized that water uptake of CO 2 provides excess H + which decreases 16 electrostatic bridges of oil-brine-sandstone system thus increasing hydrophilicity. To test our 17 hypothesis, we conducted three sets of contact angle measurements in non-carbonated and 18 carbonated brines using muscovite substrates at pressure of 3000 psi and temperature of 25 o C. 19 Moreover, we performed a geochemical study to quantify how excess H + governs electrostatic bridges 20 in oil-brine-muscovite system bearing with basal charged clays. 21 Our contact angle measurements show that non-carbonated water gave a contact angle of 118 o , 22 whereas carbonated brine gave a contact angle of 30 o , implying a strong hydrophilic system. 23 Geochemical modelling demonstrates that excess H + substantially substitutes exchangeable cations 24 (>Na) embedded in muscovite thus decreasing electrostatic bridges between oil-brine-muscovite. This 25 work provides a first quantitative investigation on how water uptake of CO 2 depresses ion exchange 26 process between oil-brine-muscovite and thus leading to wettability alteration.
Fuel, 2018
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 SO 4 2-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 ([ > CaOH 2 + ][-COO − ] + [ > CO 3 − ][-NH + ] + [ > CO 3 − ][-COOCa + ]) increased with decreasing salinity. 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.
Carbon dioxide injection in carbonate reservoirs – a review of CO 2 -water-rock interaction studies
Carbon dioxide injection in geological formations is currently a common procedure in several reservoirs worldwide. More recently, it has been considered a permanent storage solution, avoiding emission to the atmosphere from large industrial sources. Also, it is largely employed in the oil & gas exploration industry, for enhanced oil recovery (EOR) operations. However, it is a known fact that injection of large amounts of CO 2 into geological reservoirs may lead to a series of alterations due to chemical and physical interactions with minerals and fluids, especially in carbonate or carbonate-rich reservoirs. Experimental and numerical models have been employed in many studies in the past, to investigate these effects on the geological environment. So far, most of these studies focused on siliciclastic formations, whereas carbonate reservoirs, which are known to be much more chemically reactive when interacting with CO 2 , were much less investigated. We present a review of experimental and numerical models that have been employed for studying CO 2-water-rock interactions, and their application to the investigation of the impact in carbonate reservoir quality and integrity caused by the injection of carbon dioxide. C
Journal of Molecular Liquids, 2020
Carbonated water flooding (CWF) appears to be an important means in enhanced oil recovery (EOR) in carbonate reservoirs. While a few CWF coreflooding experiments have been done to reveal the controlling factor(s) behind incremental oil recovery, few has examined the impact of calcite dissolution on the contribution of the proposed mechanisms, and fewer have looked beyond the impact of calcite dissolution on different length scale (from core to reservoir). We thus conducted a series of core flooding experiments to investigate the residual oil saturation and recovery factor during waterflooding with and without carbonation. We also imaged the core plugs using a computed tomography scanner to examine the evolution of calcite dissolution along the core plug. Furthermore, we performed 1D reactive transport modelling at core-and reservoir-length-scale to delineate the impact of calcite dissolution process during carbonated waterflooding. Coreflooding experiments confirm that lowering salinity increases oil recovery from 53% to 64.5% without carbonation. However, low salinity carbonated water at secondary mode yielded 47.6% and 52% oil recovery, between 1 and 5.4% less recovery compared to formation brine flooding without carbonation, lower than the formation brine flooding without carbonation. Carbonated waterflooding also resulted in a significantly increases of permeability. CT images clearly show the generation of wormholes along the core, accounting for the low recovery and increased rock permeability. 1D reaction transport modelling at core-scale reveals the calcite dissolution taking place throughout the core plugs, supporting the wormholes evolution from CT images. Onedimensional reactive transport modelling at reservoir-scale shows the calcite dissolution distance from wellbore increases from 13 to 45 m with increasing flow rate from 0.05 to 1 m/day. Taken together, our results imply that calcite dissolution may deteriorate heterogeneity of reservoirs particularly near the wellbore. This may significantly undermine the contribution of oil-swelling, viscosity reduction, IFT reduction and wettability alteration on incremental oil recovery, as well as wellbore stability. However, the negative impact of calcite dissolution may not prevail at in-depth of reservoirs because the calcite dissolution would reach equilibrium at a certain distance, which is also associated with injection rates.
Geochemical insights for CO2 huff-n-puff process in shale oil reservoirs
Journal of Molecular Liquids, 2020
CO 2 huff-n-puff process appears to be important to unlock hydrocarbon resources from shale oil reservoirs after multi-stage hydraulic fracturing. While existing literature shows that CO 2 diffusion plays a significant role in kinetics of oil recovery, few studies have been able to draw on any systematic research into fluid-shale interaction due to water uptake of CO 2 in connate water (water carbonation), which governs fluids flow in fractures thus CO 2 huff-n-puff performance. We therefore hypothesized that water carbonation would depress ion exchange process between oil and organic matter (OM) thus forming a more water-wet system. Moreover, water carbonation would also decrease the electrostatic forces between oil and edge charge on OM, thereby further promoting water-wet system. To test the hypothesis, we measured contact angles in non-carbonated high salinity brine (HS), carbonated high salinity brine (CO 2 HS) and carbonated low salinity brine (CO 2 LS) at temperature of 25°C and under pressure of 3000 psi. Moreover, a geochemical modelling was conducted to evaluate ion exchange and surface complexation reactions in three different brines. Our contact angle measurements showed that HS gave a contact angle of 130°, while CO 2 HS and CO 2 LS resulted a contact angle of 23.5°and 23.0°, suggesting a more water-wet system. Geochemical modelling shows that ion exchange reactions between oil and shale surfaces are dramatically depressed in carbonated brine. In particular, the bridges number between oil and shale surfaces decreases from 5.2 × 10 −4 μmol/m 2 to 5.3 × 10 −6 μmol/m 2 in carbonated brines, supporting the contact angle measurements. Moreover, the computed surface potential at oil and rock surfaces increases from around −40 mV to 150 mV, suggesting more repulsive forces in the presence of carbonated brine, further supporting contact angle results. This work reveals for the first time that water carbonation during CO 2 huff-n-puff process likely triggers a hydrophilic shale surface, which may significantly affects multiphase flow in natural and hydraulic fractures in particular.
Laboratory studies have shown that wettability of carbonate rock can be altered to a less oil-wetting state by manipulation of brine composition and reduction of salinity. Our recent study (see suggests that a surface-charge change is likely to be the driving mechanism of the low salinity effect in carbonates. Various studies have already established the sensitivity of carbonate surface charge to brine salinity, pH and potential-determining ions in brines. However, it has been less investigated i) whether different types of carbonate reservoir rocks exhibit different electrokinetic properties, ii) how the rocks react to reservoir-relevant brine as well as successive brine dilution and iii) how the surface charge behavior at different salinities and pH can be explained.