Abstract:The success of CO 2 storage in deep saline aquifers and depleted oil and gas reservoirs is largely controlled by interfacial phenomena among fluid phases and rock pore spaces. Particularly, the wettability of the rock matrix has a strong effect on capillary pressure, relative permeability, and the distribution of phases within the pore space and thus on the entire displacement mechanism and storage capacity. Precise understanding of wettability behavior is therefore fundamental when injecting CO 2 into geologi… Show more
“…As the pressurized CO 2 is pumped underground, it warms to in situ temperature of the storage reservoir; under the pressure and temperature conditions of most reservoirs targeted for CO 2 sequestration, the injected CO 2 will exist in a supercritical state (denoted scCO 2 in the present study) [Intergovernmental Panel on Climate Change, 2005;Benson and Cole, 2008]. Sandstones and other sedimentary formations provide favorable storage conditions [Bachu, 2003;Gunter et al, 2004]; and although wettability measurements of scCO 2 -brine-geologic media systems are thus far inconclusive [Wan et al, 2014], for sandstone formations, aqueous brine has been observed to be the dominant wetting phase while scCO 2 is the nonwetting phase Krevor et al, 2012;Pini and Benson, 2013;Herring et al, 2014;Kaveh et al, 2014]; these observations are supported by measurements of water-wet (or weakly water-wet) contact angles on surfaces representative of sandstones [Chaudhary et al, 2015]. The nomenclature used in the following reflects this assumption of water-wet porous media.…”
We utilize synchrotron X‐ray tomographic imaging to investigate the pore‐scale characteristics and residual trapping of supercritical CO2 (scCO2) over the course of multiple drainage‐imbibition (D‐I) cycles in Bentheimer sandstone cores. Capillary pressure measurements are paired with X‐ray image‐derived saturation and connectivity metrics which describe the extent of drainage and subsequent residual (end of imbibition) scCO2 trapping. For the first D‐I cycle, residual scCO2 trapping is suppressed due to high imbibition capillary number (Ca ≈ 10−6); however, residual scCO2 trapping dramatically increases for subsequent D‐I cycles carried out at the same Ca value. This behavior is not predicted by conventional multiphase trapping theory. The magnitude of scCO2 trapping increase is hysteretic and depends on the relative extent of the sequential drainage processes. The hysteretic pore‐scale behavior of the scCO2‐brine‐sandstone system observed in this study suggests that cyclic multiphase flow could potentially be used to increase scCO2 trapping for sequestration applications.
“…As the pressurized CO 2 is pumped underground, it warms to in situ temperature of the storage reservoir; under the pressure and temperature conditions of most reservoirs targeted for CO 2 sequestration, the injected CO 2 will exist in a supercritical state (denoted scCO 2 in the present study) [Intergovernmental Panel on Climate Change, 2005;Benson and Cole, 2008]. Sandstones and other sedimentary formations provide favorable storage conditions [Bachu, 2003;Gunter et al, 2004]; and although wettability measurements of scCO 2 -brine-geologic media systems are thus far inconclusive [Wan et al, 2014], for sandstone formations, aqueous brine has been observed to be the dominant wetting phase while scCO 2 is the nonwetting phase Krevor et al, 2012;Pini and Benson, 2013;Herring et al, 2014;Kaveh et al, 2014]; these observations are supported by measurements of water-wet (or weakly water-wet) contact angles on surfaces representative of sandstones [Chaudhary et al, 2015]. The nomenclature used in the following reflects this assumption of water-wet porous media.…”
We utilize synchrotron X‐ray tomographic imaging to investigate the pore‐scale characteristics and residual trapping of supercritical CO2 (scCO2) over the course of multiple drainage‐imbibition (D‐I) cycles in Bentheimer sandstone cores. Capillary pressure measurements are paired with X‐ray image‐derived saturation and connectivity metrics which describe the extent of drainage and subsequent residual (end of imbibition) scCO2 trapping. For the first D‐I cycle, residual scCO2 trapping is suppressed due to high imbibition capillary number (Ca ≈ 10−6); however, residual scCO2 trapping dramatically increases for subsequent D‐I cycles carried out at the same Ca value. This behavior is not predicted by conventional multiphase trapping theory. The magnitude of scCO2 trapping increase is hysteretic and depends on the relative extent of the sequential drainage processes. The hysteretic pore‐scale behavior of the scCO2‐brine‐sandstone system observed in this study suggests that cyclic multiphase flow could potentially be used to increase scCO2 trapping for sequestration applications.
“…[] and Kaveh et al . [], contact angle measurements depend on equilibration time between the fluids and the solid and on bubble size. They found that contact angle increases with progressing equilibration time but decreases with bubble radius if placed underneath the solid surface.…”
Section: Co2‐wettability Of Caprock and Storage Rock Mineralsmentioning
confidence: 99%
“…Kaveh et al . [] measured captive drop contact angles for the Bentheimer sandstone‐CO 2 ‐water system. The sandstone consisted of 96% quartz, ∼2% feldspars, and ∼2% kaolinite, and the kaolinite was homogeneously distributed throughout the rock matrix.…”
Section: Co2‐wettability Of Caprock and Storage Rock Mineralsmentioning
We review the literature data published on the topic of CO 2 wettability of storage and seal rocks. We first introduce the concept of wettability and explain why it is important in the context of carbon geo-sequestration (CGS) projects, and review how it is measured. This is done to raise awareness of this parameter in the CGS community, which, as we show later on in this text, may have a dramatic impact on structural and residual trapping of CO 2 . These two trapping mechanisms would be severely and negatively affected in case of CO 2 -wet storage and/or seal rock. Overall, at the current state of the art, a substantial amount of work has been completed, and we find that:Sandstone and limestone, plus pure minerals such as quartz, calcite, feldspar, and mica are strongly water wet in a CO 2 -water system.Oil-wet limestone, oil-wet quartz, or coal is intermediate wet or CO 2 wet in a CO 2 -water system.The contact angle alone is insufficient for predicting capillary pressures in reservoir or seal rocks.The current contact angle data have a large uncertainty.Solid theoretical understanding on a molecular level of rock-CO 2 -brine interactions is currently limited.In an ideal scenario, all seal and storage rocks in CGS formations are tested for their CO 2 wettability.Achieving representative subsurface conditions (especially in terms of the rock surface) in the laboratory is of key importance but also very challenging.
“…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.
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