Abstract:Wettability plays a crucial role on the performance of enhancing oil recovery techniques because of its effect on fluid saturations and flow behavior in porous medium. This study is directed toward determining contact angles (i.e., wettability) in systems with carbon dioxide, brine, and an oil-saturated rock system. Two situations are considered: Rock system I is partially water-wet, whereas rock system II is effectively oil-wet. Contact angles have been determined experimentally as a function of brine salinit… Show more
“…Furthermore, wettability alteration by CO 2 dissolution in brine has already been investigated for the systems of CO 2 -water-coal 9-11 , CO 2 -brine-Mica 12, 13 , CO 2 -brine-Quartz 12, 14 , CO 2reservoir brine-reservoir rock [15][16][17][18] and CO 2 -water-glass 19,20 ; however, very limited study focus on the wettability alteration of oil-brine-rock system with dissolution of CO 2 21 . Grape et al 22 performed imbibition tests involving CO 2 -enriched water (carbonated water).…”
Carbonated (CO 2 -enriched) water injection has been shown to improve waterflood performance over conventional water flood. Carbonated water can be purposely injected in an oil reservoir but it also forms spontaneously during conventional CO 2 floods or CO 2 WAG injection. It is therefore important to understand the rock-fluid and fluid-fluid interactions that take place in an oil reservoir when carbonated water contacts the oil and the reservoir rock. Due to dissolution of CO 2 in brine, the pH of injection water is reduced during carbonated water injection. This reduction in brine pH may affect the electric charges on water-rock interfaces and hence, may alter the wetting characteristics of the surface. This wettability alteration will have a direct effect on oil recovery and the amount of oil remaining after waterflood.In order to assess and quantify the extent of possible wettability alteration due to carbonation of water a series of contact angle measurements have been performed in this study. Three different minerals namely; Quarts, Mica, and Calcite were exposed to plain and then carbonated water under a wide range of pressures between 100 and 3500 psi. The temperature of the measurements was kept constant at 100 ⁰F. For each mineral, two situations were considered; an un-aged (clean) rock system and an aged rock system. The captive bubble method was used for measuring the contact angles.The results for the un-aged measurements show that carbonated water can change the wettability of clean minerals in varying degrees. The observed change in the measured contact angles was a function of pressure and it increased as the pressures increased. For the un-aged substrates, the change in wettability by carbonated water was moderate with the maximum change of around 6 degrees taking place for Quartz.The results of the aged minerals revealed a much higher change in wettability by carbonated water compared to the un-aged substrates. For the aged quartz sample, at the pressure of 2500 psi, when CO 2 was introduced to the top of plain brine and CW was formed, the contact angle changed from 76 to 61, and for the aged mica at the same pressure the contact angle changed from 89 to 63. For the aged Calcite, carbonated water brought about a larger change in wettability with the contact angle changing from 144 to 97.The results of the study show that under real reservoir conditions where the rock is usually mixed-wet or oil-wet, the dissolved CO 2 content of water can have a major impact on the wettability of the reservoir, which in turn would significantly affect the oil displacement efficiency and the recovery factor.
“…Furthermore, wettability alteration by CO 2 dissolution in brine has already been investigated for the systems of CO 2 -water-coal 9-11 , CO 2 -brine-Mica 12, 13 , CO 2 -brine-Quartz 12, 14 , CO 2reservoir brine-reservoir rock [15][16][17][18] and CO 2 -water-glass 19,20 ; however, very limited study focus on the wettability alteration of oil-brine-rock system with dissolution of CO 2 21 . Grape et al 22 performed imbibition tests involving CO 2 -enriched water (carbonated water).…”
Carbonated (CO 2 -enriched) water injection has been shown to improve waterflood performance over conventional water flood. Carbonated water can be purposely injected in an oil reservoir but it also forms spontaneously during conventional CO 2 floods or CO 2 WAG injection. It is therefore important to understand the rock-fluid and fluid-fluid interactions that take place in an oil reservoir when carbonated water contacts the oil and the reservoir rock. Due to dissolution of CO 2 in brine, the pH of injection water is reduced during carbonated water injection. This reduction in brine pH may affect the electric charges on water-rock interfaces and hence, may alter the wetting characteristics of the surface. This wettability alteration will have a direct effect on oil recovery and the amount of oil remaining after waterflood.In order to assess and quantify the extent of possible wettability alteration due to carbonation of water a series of contact angle measurements have been performed in this study. Three different minerals namely; Quarts, Mica, and Calcite were exposed to plain and then carbonated water under a wide range of pressures between 100 and 3500 psi. The temperature of the measurements was kept constant at 100 ⁰F. For each mineral, two situations were considered; an un-aged (clean) rock system and an aged rock system. The captive bubble method was used for measuring the contact angles.The results for the un-aged measurements show that carbonated water can change the wettability of clean minerals in varying degrees. The observed change in the measured contact angles was a function of pressure and it increased as the pressures increased. For the un-aged substrates, the change in wettability by carbonated water was moderate with the maximum change of around 6 degrees taking place for Quartz.The results of the aged minerals revealed a much higher change in wettability by carbonated water compared to the un-aged substrates. For the aged quartz sample, at the pressure of 2500 psi, when CO 2 was introduced to the top of plain brine and CW was formed, the contact angle changed from 76 to 61, and for the aged mica at the same pressure the contact angle changed from 89 to 63. For the aged Calcite, carbonated water brought about a larger change in wettability with the contact angle changing from 144 to 97.The results of the study show that under real reservoir conditions where the rock is usually mixed-wet or oil-wet, the dissolved CO 2 content of water can have a major impact on the wettability of the reservoir, which in turn would significantly affect the oil displacement efficiency and the recovery factor.
“…It has been found that CO 2 -EOR and successful CO 2 sequestration are largely controlled by the interfacial characteristics among the injected CO 2 , the reservoir crude oil, the brine and the rock. [6][7][8][9] The interfacial tension (IFT) under high pressure directly relates to the capillary pressure, the maximum storage height of CO 2 , and the flow behaviors in porous media. [9][10][11] If the reservoir pressure is higher than the minimum miscibility pressure (MMP), CO 2 and oil become completely miscible 12 and they contact with brine together at the interface.…”
In the carbon dioxide (CO 2 )-enhanced oil recovery (EOR) process and the subsequent geological CO 2 sequestration, a ternary system consisting of CO 2 , crude oil and brine exists in the reservoir due to the common practice of injecting CO 2 together with brine. In this paper, we carried out molecular dynamics simulations to study the interfacial properties of the ternary CO 2 , hexane and 1.52 mol/L sodium chloride (NaCl) solution system under 330 K and 20 MPa with different CO 2 compositions at the supercritical state, which are very important for the efficiency of the EOR and CO 2 sequestration processes. We observed that CO 2 mixes well with hexane and a clear interface separates the CO 2 -hexane mixture with the NaCl solution. The interfacial roughness increases with the CO 2 composition, indicating deeper molecular penetrations and shorter capillary wave lengths, which leads to the reduced interfacial tension. Interestingly, the surface excess of CO 2 reaches maximum at a CO 2 molar fraction of 62.5% (or a weight fraction of 46%), which implies the amphiphilic feature of CO 2 , acting like surfactants, towards the hexane-brine interface. The orientational preferences of CO 2 , hexane and water molecules at the interface are more random at higher CO 2 compositions, as a result of the increased absolute amount of CO 2 and the absence of hexane at the interface.
“…IFEMA Madrid, Spain, 1-4 June 2015 1-4 June 2015 | IFEMA Madrid the measurements (Ameri et al 2013, Shojai Kaveh et al 2014. When the aqueous phase is not completely saturated with CO 2 , the injectivity and the gas distribution in the reservoir are not only influenced by the rock properties but also by the diffusion of CO 2 into the aqueous phase (Shojai Kaveh et al 2011, Shojai Kaveh et al 2012).…”
SUMMARYFor a water-saturated cap-rock, which consists of a low-permeability porous material, the wettability of the reservoir rock-connate water-CO2 system and the interfacial tension (IFT) between CO2 and connate water are the significant parameters for the evaluation of the capillary sealing. Also, the amount of capillary-trapped CO2 depends on the wettability of reservoir rocks. The wettability of the rock matrix has a strong effect on the distribution of phases within the pore space and thus on the entire displacement mechanism and storage capacity. In this work, the equilibrium contact angles of water/shale system were determined with CO2 for a wide range of pressures at a constant temperature of 318 K by using the dynamic captive bubble method. The results reveal that intermediate-wet conditions and hence possible leakage of CO2 must to be considered at relatively high pressures, however, the salt concentration of the water in the shales plays an important role too. The results show that this estimate is highly dependent on the pore structure, fluid composition and pressure/temperature conditions of the reservoirs. These properties need to be first evaluated before estimates for shale capillarity is used.
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