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In this work, four linear alkyl ether carboxylates (AECs) C11E5A, C11E11A, C12E4A, and C12E7A were examined as agents for surfactant EOR. Their main properties that have a key effect on surfactants' performance during flooding were investigated: stability, interfacial tension (IFT), wetting ability, and spontaneous imbibition in limestone samples. The thermal stability and salinity tolerance was correlated with the molecular structure of AECs. IFT on the boundary with n-decane and crude oil was evaluated with the spinning drop tensiometry method at five temperatures in the range between 25°C and 70°C and various salinities. The wettability was studied through contact angle measurements of deionized water on the limestone plate surface. The core plates were aged in oil for 14 days to obtain the hydrophobic carbonate surface and then treated with surfactant compositions for 48 hours at 70°C. The wettability alteration mechanism was assessed through the Rock-Eval pyrolysis method, which was not previously applied for this purpose. The experiments showed that ethylene oxide (EO) chain length influences the stability of AECs. It was found that the temperature rise substantially impacts a surfactant with a longer EO chain C11E11A. In contrast, brine salinity significantly affects the interfacial behavior of AEC with a shorter EO chain. C12E7A strongly hydrophilizes the surface, and the contact angle decreases from 110° to 15÷20°. The Rock-Eval pyrolysis analysis indicated that C12E7A has a better wetting ability due to a combination of "cleaning" (washing of hydrocarbons from the core sample surface) and "coating" (adsorption of surfactant molecules on cleaned spaces) mechanisms.

Hypothesis The advanced low salinity aqueous formulations are yet to be validated as an injection fluid for enhanced oil recovery (EOR) from the carbonate reservoirs and CO2 geosequestration. Interaction of various ionic species present in the novel low salinity surfactant nanofluids with scCO2/CO2 saturated aqueous phase interface and at the interface of CO2 saturated aqueous phase/mixed wet (with CO2 and Decane) limestone surface at the conditions of low salinity at reservoir conditions are to yet to be understood. Experiments This study, carried out for the first time in low salinity at scCO2 loading conditions at 20 MPa pressure and 343 K temperature, comprises of wettability study of the limestone surface by aqueous phase contact angle measurements using ZrO2 nanoparticles (in the concentration range of 100–2000 mg/L) and 0.82 mM Hexadecyltrimethylammonium bromide (CTAB) surfactant. Molecular dynamics simulations results were used to understand the underlying mechanism of wettability alteration and interfacial tension (IFT) change. Findings This study reveals that a low dosage (100 mg/L) of ZrO2 nanoparticles forming ZrO2-CTAB nano-complexes helps in wettability alteration of the rock surface to more water-wetting state; certain ionic species augment this effect when used in appropriate concentration. Also, these nano-complexes helps in scCO2/CO2 saturated aqueous phase IFT reduction. This study can be used to design advanced low salinity injection fluids for water alternating gas injection for EOR and CO2 geosequestration projects.

The absorption of acid gas using reactive amines is among the most widely used types of capturing technologies. However, the absorption process requires intensive energy expenditure majorly in the solvent regeneration process. This study simultaneously evaluated the regeneration energy of MDEA and PZ/MDEA solvents in terms of heat of absorption, sensible heat, and vaporization heat. Aspen Hysys version 8.8 simulation tool is applied to model the full acid gas removal plant for the chemical absorption process. The new energy balance technique presents around the absorption and desorption columns to bring a new perspective of energy distribution in the capturing of acid gas plants. Sensitivity analysis of regeneration energy and its three contributors is performed at several operation parameters such as absorber and stripper pressures, lean amine circulation rate, solvent concentration, reflux ratio, and CO2 and H2S concentrations. The results show that the heat of absorption of PZ/MDEA system is higher than that for MDEA system for the same operating conditions. The sensible heat is the main contributor in the required regeneration energy of MDEA solvent system. The simulation results have been validated against data taken from real plant and literature. The product specifications of our simulation corroborate with real plant data in an excellent approach; additionally, the profile temperature of the absorber and the stripper columns are in good agreement with literature. The overall results highlight the direction of the effects of each parameter on the heat of absorption, sensible heat, and vaporization heat.

Previous studies have demonstrated that formic and glycolic acids could scavenge oxygen from aqueous solutions via complex radical mechanisms similar to that of erythorbic acid. Therefore, it is important to study the feasibility of using these common thermal degradation products obtained from the regeneration of monoethylene glycol (MEG). By replacing commercially used oxygen scavengers, such as sulfites, with these organic acids, the toxicity and subsequent environmental impact of oil and gas products could be easily reduced. Furthermore, these organic acids are rapid oxygen scavengers at low concentration, and they could be cost-effective; in addition, the chemical inventory could be reduced and project costs could be further optimized. The experimental results confirmed the potential of formic and glycolic acids to be used as oxygen scavengers downstream of the MEG regeneration process in the presence of manganese (II) ions as catalyst. Of the two commercial aqueous industrial oxygen scavengers tested, diethylhydroxylamine was an extremely rapid oxygen scavenger in salty aged lean MEG solutions under alkaline conditions, whereas methyl ethyl ketoxime exhibited extremely poor performance under similar conditions; therefore, it was ruled out as potential oxygen scavenger.

Wettability is one of the main parameters controlling CO2 injectivity and the movement of CO2 plume during geological CO2 sequestration. Despite significant research efforts, there is still a high uncertainty associated with the wettability of CO2/brine/rock systems and how they evolve with CO2 exposure. This study, therefore, aims to measure the contact angle of sandstone samples with varying clay content before and after laboratory core flooding at different reservoir pressures, of 10 MPa and 15 MPa, and a temperature of 323 K. The samples’ microstructural changes are also assessed to investigate any potential alteration in the samples’ structure due to carbonated water exposure. The results show that the advancing and receding contact angles increased with the increasing pressure for both the Berea and Bandera Gray samples. Moreover, the results indicate that Bandera Gray sandstone has a higher contact angle. The sandstones also turn slightly more hydrophobic after core flooding, indicating that the sandstones become more CO2-wet after CO2 injection. These results suggest that CO2 flooding leads to an increase in the CO2-wettability of sandstone, and thus an increase in vertical CO2 plume migration and solubility trapping, and a reduction in the residual trapping capacity, especially when extrapolated to more prolonged field-scale injection and exposure times.

As the search for natural resources extends into ever deepening waters, the oil and gas industry is faced with numerous flow assurance challenges ranging from corrosion to gas hydrate formation. Methyldiethanolamine (MDEA) is a chemical that is widely used for corrosion protection through the pH stabilization method. It is usually injected alongside monoethylene glycol (MEG) which is used as a hydrate inhibitor. In recent studies, MDEA has been found to have an inhibiting effect on gas hydrate formation. This inhibitory effect is neither taken into account in field hydrate control programs nor in simulation software. To date, the effect has only been modeled empirically by the authors. In this study, thermodynamic modeling has been conducted using the cubic plus association equation of state (CPA EoS) combined with van der Waals and Platteeuw’s solid solution theory for hydrate phase equilibria. This application of the CPA EoS will allow for accurate prediction of hydrate equilibria of MDEA solutions used...

Monoethylene glycol (MEG) is extensively used in oil and gas pipelines to prevent the formation of gas hydrates. However, the injection of MEG may inadvertently contribute to mineral-ion precipitation through reduced solubility of ionic species and operation under alkaline conditions for corrosion control. As a result, the injection of chemical scale inhibitors (CSI) to manage scaling is often required. Non-chemical inhibitors, such as external magnetic fields (MFs) have also been shown to inhibit scaling in aqueous solutions. With this in mind, we investigated the combined application of CSIs and MF treatment to study the formation of scale under conditions representative of a MEG regeneration system's reboiler, a system under a high risk of scale formation. Two commercial CSIs were examined in the presence and absence of a 0.650-T external MF using a dynamic-scale-loop device. The CSIs were injected into ionic solutions containing 1656.9 ppm calcium ions and 2628 ppm carbonate ions in aqueous MEG (80 vol%), and experiments were performed at 130 °C and pH 9.5. Despite the presence of a CSI, the MF promoted scale formation and afforded a stable calcium carbonate phase morphology at high MEG concentrations. Moreover, the zeta potential under the applied MF was lower than that in the absence of the MF, which led to greater scaling, implying that the magnetic field had an ionic interfacial effect. These results provide significant insight into the effect of a MF on scale formation, irrespective of the use of a CSI, and help to interpret the effects of various treatments for scale removal or the prevention of scale formation during the MEG regeneration process.

The use of methyldiethanolamine (MDEA) as a pH stabilizer in natural gas pipelines utilizing monoethylene glycol (MEG) injection is an attractive option in systems with high carbon dioxide (CO2) pa...

Advanced low-salinity aqueous formulations have shown promising results for rock wettability modification and interfacial tension reduction. Additives, such as surfactant and nanoparticles, can be ...

Hydrate formation is a serious concern in the production and transportation of natural gas. While there exist numerous hydrate inhibitors, there are a plethora of other chemicals that are also pres...

The breakthrough of formation water increases the risk not only of gas hydrate formation but also of corrosion. Switching between corrosion strategies may be necessary as formation water increases the risk of scale formation in the presence of methyl diethanolamine (MDEA), acetic acid, and cations. The switchover from pH stabilization with MDEA to a film-forming corrosion inhibitor (FFCI) was investigated when studying the effect of pH changes on the removal of MDEA, FFCI, acetic acid, and salts in the reclamation unit. The natural gas hydrate inhibitory performance (35 wt%) of the reclaimed monoethylene glycol (MEG) samples were also assessed. The study found that an optimum operating pH for the whole system was not achievable because of the contrasting pH requirements in the pretreatment and reclamation units. The study recommends operating the pretreatment unit at pH > 8 to precipitate out the divalent salts, and injecting acid before the regeneration unit, which allows for the volatile acetic acid to be removed via the reflux drum. We found that FFCI and MDEA accumulation in the reclamation unit resulted in a highly viscous residue (1430.53 mPa-s) and a discoloration (from brown to very dark brown). Further, new natural gas hydrate equilibria data for reclaimed MEG have been reported. The performance of reclaimed MEG varied compared with that of pure MEG, and was lower at the end of the experiment, whereas MDEA showed a hydrate-inhibiting effect.

Monoethylene glycol (MEG) is often used in offshore multiphase hydrocarbon transportation pipelines to prevent the formation of natural gas hydrates. Post hydrate inhibition, MEG is separated along...

Wettability of CO2-brine-mineral systems plays a vital role during geological CO2-storage. Residual trapping is lower in deep saline aquifers where the CO2 is migrating through quartz rich reservoirs but CO2 accumulation within a three-way structural closure would have a high storage volume due to higher CO2 saturation in hydrophobic quartz rich reservoir rock. However, such wettability is only poorly understood at realistic subsurface conditions, which are anoxic or reducing. As a consequence of the reducing environment, the geological formations (i.e. deep saline aquifers) contain appreciable concentrations of various organic acids. We thus demonstrate here what impact traces of organic acids exposed to storage rock have on their wettability. Technically, we tested hexanoic acid, lauric acid, stearic acid and lignoceric acid and measured wettability as a function of organic acid concentration at realistic storage conditions (i.e. 25 MPa and 323 K (50 °C)). In addition, measurements were also conducted at ambient conditions in order to quantify the incremental pressure effect on wettability. Clearly, the quartz surface turned significantly less water-wet with increasing organic acid concentrations, even at trace concentrations. Importantly, we identified a threshold concentration at ˜10−6 M organic acid, above which quartz wetting behaviour shifts from strongly water-wet to an intermediate-wet state. This wettability shift may have important consequences for CO2 residual trapping capacities, which may be significantly lower than for traditionally assumed water-wet conditions where CO2 is migrating through quartz rich reservoirs.

Hypothesis: Separation of CO2 from a stream of natural gas using low-temperature distillation process is complicated not only because of the existence of ethane (C2) and CO2 azeotrope but owing to ...

One of the major challenges faced by oil extraction industry is the unstable behavior of asphaltene formation, yet not fully understood. The prediction of asphaltene formation depends on the small changes in chemical characteristics and composition of the crude oil. Consequently, the study of molecular structure and molecular properties such as density is of a great practical interest. Other properties become very complex to assess when the asphaltene fraction contains 105 different molecules. Average molecular parameters are used to obtain information about asphaltenes. The density of the asphaltenes can easily be calculated and, thus, can be used to evaluate predictive capacities of the average structure. This present work of molecular dynamic simulations was carried out to evaluate the asphaltene densities of an Australian oil field. Simulations of molecular dynamics are used to assess the average structure densities representing different asphaltenes in a specific oil field. These simulations assist in predicting the formation of asphaltene structural model. Comparatively, the experimental densities are higher than the calculated ones. However, the calculated values demonstrate the appropriate trend. The chemical structure shows essential accuracy, as evidenced by average structures, which can be used to estimate the densities qualitatively. Hence, systematic study was carried out on the basis of the effects of various structures on the calculated densities of asphaltene. The main characteristics of the molecules which yielded highest densities are those found with low hydrogen–carbon ratio and big condensed aromatic rings. Moreover, better and improved density values were produced by a recently developed group contribution method than simulations of molecular dynamics, which is still being lower than that of experimental values.

One of the most discussed topics related to the effects of external magnetic fields (MF) on aqueous solutions is the influence on the scale formation of calcium carbonate (CaCO3). However, the extent of the effect of these forces on the scale formation in the non-aqueous solutions has not been investigated so far. So MFs will be applied to non-aqueous mixtures to find out the behavior of scale formation. This study presents the results of inorganic scale formation within MEG solutions containing Ca2+ and HCO3− ions, which has been investigated using both static and dynamic scale loop (DSL) evaluation techniques. Furthermore, the influence of MFs on scale formation using the dynamic technique has also been studied. Results were generated using brine/MEG solutions exposed to an external MF produced by a 0.65 T Neodymium magnet for 2.5 s. The degree of scale formation was examined by measuring the pressure build-up across a capillary coil as scale was developed. Moreover, differences in CaCO3 morphologies were evaluated for the exposed and blank trials via the DSL technique and compared with the results obtained from the static scale evaluation method. The results of this research have demonstrated that the short exposure (2.5 s) to a powerful MF can significantly reduce scale-formation in the rich MEG solutions within the capillary coil. This is due to the alteration of the proton spin inversion in the field of diamagnetic salts. Furthermore, a significant difference in CaCO3 morphology was observed for the scale formed during dynamic and static conditions. The generating results help to reduce the use of chemical scale inhibitors with MEG solution during the gas hydrate treatments, especially when the concentration of MEG in formation water is low and scale formation is more likely to occur.

Low-salinity water injection emerges to be a cost-effective and environmentally friendly enhanced oil recovery technique. Furthermore, additives, such as the surfactant and nanoparticles in combina...

Hypothesis CO2 geological storage (CGS) involves different mechanisms which can store millions of tonnes of CO2 per year in depleted hydrocarbon reservoirs and deep saline aquifers. But their storage capacity is influenced by the presence of different carboxylic compounds in the reservoir. These molecules strongly affect the water wetness of the rock, which has a dramatic impact on storage capacities and containment security. However, precise understanding of how these carboxylic acids influence the rock’s CO2-wettability is lacking. Experiments We thus systematically analysed these relationships as a function of pressure, temperature, storage depth and organic acid concentrations. A particular focus was on identifying organic acid concentration thresholds above which storage efficiency may get influenced significantly. Findings These thresholds (defined for structural trapping as a water contact angle θ > 90°; and for capillary trapping when primary drainage is unaffected, i.e. θ > 50°) were very low for structural trapping (∼10−3–10−7 M organic acid concentration Corganic) and extremely low for capillary trapping (10−7 M to below 10−10 M Corganic). Since minute organic acid concentrations are always present in deep saline aquifers and certainly in depleted hydrocarbon reservoirs, significantly lower storage capacities and containment security than previously thought can be predicted in carbonate reservoirs, and reservoir-scale models and evaluation schemes need to account for these effects to de-risk CGS projects.

Wettability of CO2/brine/clay is one of the most important parameters in assessing CO2 storage capacities and containment security. Despite its importance, the literature data in this context are v...

A potential alternative energy resource to meet energy demands is the vast amount of gas stored in hydrate reserves. However, major challenges in terms of exploration and production surround profitable and effective exploitation of these reserves. The measurement of acoustic velocity is a useful method for exploration of gas hydrate reserves and can be an efficient method to characterize the hydrate-bearing sediments. In this study, the compressional wave velocity (P-wave velocity) of consolidated sediments (Bentheimer) with and without tetrahydrofuran hydrate-bearing pore fillings were measured using the pulse transmission method. The study has found that the P-wave velocity of consolidated sediments increase with increasing hydrate formation and confining pressure. Of the two samples tested, the increase in wave velocity of the dry and hydrate-bearing samples amounted to 27.6% and 31.9%, respectively. Interestingly, at the initial stage of hydrate formation, there was no change in P-wave velocity, which was followed by a steady increase as the hydrate crystals began to agglomerate and then it increased rapidly to a constant value, suggesting that the test solution had converted to a hydrate solid.

Hypothesis Nanofluid flooding has been identified as a promising method for enhanced oil recovery (EOR) and improved Carbon geo-sequestration (CGS). However, it is unclear how nanoparticles (NPs) influence the CO2-brine interfacial tension (γ), which is a key parameter in pore-to reservoirs-scale fluid dynamics, and consequently project success. The effects of pressure, temperature, salinity, and NPs concentration on CO2-silica (hydrophilic or hydrophobic) nanofluid γ was thus systematically investigated to understand the influence of nanofluid flooding on CO2 geo-storage. Experiments Pendant drop method was used to measure CO2/nanofluid γ at carbon storage conditions using high pressure-high temperature optical cell. Findings CO2/nanofluid γ was increased with temperature and decreased with increased pressure which is consistent with CO2/water γ. The hydrophilicity of NPs was the major factor; hydrophobic silica NPs significantly reduced γ at all investigated pressures and temperatures while hydrophilic NPs showed only minor influence on γ. Further, increased salinity which increased γ can also eliminate the influence of NPs on CO2/nanofluid γ. Hence, CO2/brine γ has low, but, reasonable values (higher than 20 mN/m) at carbon storage conditions even with the presence of hydrophilic NPs, therefore, CO2 storage can be considered in oil reservoirs after flooding with hydrophilic nanofluid. The findings of this study provide new insights into nanofluids applications for enhanced oil recovery and carbon geosequestration projects.

Carbon dioxide geo-sequestration (CGS) into sediments in the form of (gas) hydrates is one proposed method for reducing anthropogenic carbon dioxide emissions to the atmosphere and, thus reducing global warming and climate change. However, there is a serious lack of understanding of how such CO2 hydrate forms and exists in sediments. We thus imaged CO2 hydrate distribution in sandstone, and investigated the hydrate morphology and cluster characteristics via x-ray micro-computed tomography in 3D in-situ. A substantial amount of gas hydrate (∼17% saturation) was observed, and the stochastically distributed hydrate clusters followed power-law relations with respect to their size distributions and surface area-volume relationships. The layer-like hydrate configuration is expected to reduce CO2 mobility in the reservoir, and the smaller than expected hydrate surface-area/volume ratio will reduce methane production and CO2 storage capacities. These findings will aid large-scale implementation of industrial CGS projects via the hydrate route.

CO2 geological storage (CCS)isconsidered as the most promising technique to reduce atmospheric CO2emissions. However, due to the density variation between the injected supercritical CO2 and the formation water,CO2 tends to move vertically toward the air. This vertical CO2 leakage can be prevented by four trapping mechanisms (i.e. structural trapping,capillary trapping, solubility trapping, and mineral trapping). The capacities of structural and residual trapping are highly affected by rock wettability. Clay wettability is one of the crucial parametersin evaluation of CO2 geo-sequestration. However, the literature data show that there are many uncertainties associated with experimental measurements. One of these uncertainties is the influenceof the effect of gas density on the clay mineral wettability. Thus, here, we compared the wettability of a clay mineral (i.e. illite) of three different gas densities scenarios (i.e. low (Helium), moderate (Nitrogen), and high (CO2) gas densities). To do so, we measured the advancing and receding contact angle (i.e. wettability) of illite for CO2/water, nitrogen/water, and Helium/water systems at a constant (333 K) and four different pressures (5, 10, 15, and 20 MPa). The brine composition used was 4 wt% NaCl, 4 wt% CaCl2, 1 wt% MgCl2 and 1 wt% KCl, for all gas density scenarios. The results indicate that gas density has a significant effect on the clay mineral wettability and that both advancing and receding contact angles increase with an increase in gas density. The results show that a higher density gas scenario has a higher contact angle of illite, measured at the same temperature and pressure. For instance, the advancing contact angle of illite at 333 K and 20 MPa was 65° for the CO2/water system, 53° for the nitrogen/water system, and 50° for Helium/water Helium/water system. Thus, we conclude that the gas density affects the Clay wettability measurement and that the higher gas density leads to a higher contact angle measurements (i.e. a more CO2-wet system) of the clay and thus reduces the estimated CO2 geo-sequestration capacity and containment security.

Carbon dioxide capture and storage (CCS) is considered as the most promising technological method to decrease atmospheric Carbon dioxide (CO2) emissions. However, due to density difference between the injected CO2 and the formation brine, CO2 tends to move vertically upwards in the reservoir, which results in leakage risk. This vertical migration of CO2 can be prevented by four trapping mechanisms, i.e. structural/residual trapping, capillary trapping, solubility trapping, and mineral trapping. The capacities of structural and residual trapping are highly affected by rock wettability. Clay wettability is one of the crucial parameters in evaluation CO2 geo-sequestration. However, the literature data show that there are many uncertainties associated with clay experimental measurements. One of these uncertainties is the influence of the effect of gas density on the clay mineral wettability. Thus, here, we compared the wettability of a clay mineral (i.e. montmorillonite) with three different gas densities scenarios (i.e. low (Helium), moderate (Nitrogen) and high (CO2) gas densities). To do so, we measured the advancing and receding contact angle (i.e. wettability) of montmorillonite for CO2/water, nitrogen/water, and Helium/water systems at a constant (333 K) under four different pressures (5, 10, 15, and 20 MPa). The brine composition used was 4 wt% NaCl, 4 wt% CaCl2, 1 wt% MgCl2 and 1 wt% KCl, for all gas density scenarios. The results indicate that gas density has a significant effect on the clay mineral wettability and that both advancing and receding contact angles increase with an increase in gas density. The results show that the higher gas density gas has higher contact angle with montmorillonite, measured at the same temperature and pressure. For example, the advancing contact angle of montmorillonite at 333 K and 15 MPa was only 50 (water-wet) for the Helium/water system, while it was 101 (intermediate-wet) for the CO2/water system. Thus, we conclude that the gas density affects the clay wettability and that higher gas density leads to increase the CO2-wettability of the clay. This phenomenon reduces the estimated CO2 geo-sequestration capacity and containment security. This implication can be utilised to improve the wettability predictions, and thus, the assessments of reservoir CO2 geo-sequestration capacity.

CO2 injection into geological reservoirs is considered as a promising technology to improve oil recovery from oil reservoirs and to reduce greenhouse gas emissions. However, due to the density difference between the injected CO2 and formation brine, the injected CO2 tends to move vertically towards the surface. The risk of this vertical CO2 movement can be prevented by four different trapping mechanisms (i.e. structural, residual, dissolution, and mineral trapping). From the dissolution of CO2 in the aquifer brine, carbonic acid will be formed. Then, this carbonic acid will be reacted with rock minerals and resulted in mineral dissolution and precipitation. However, the effect of these mineral interactions on the porosity-permeability evolution during the CO2 storage process in the sandstone reservoir has not been addressed effectively. Thus, here, we developed a 3D reservoir simulation model to investigate the effect of mineral interactions on the reservoir porosity and permeability during CO2 injection and storage processes in a sandstone reservoir. The multicomponent, chemically reactive, non-isothermal and multiphase flow numerical simulation program TOUGHREACT has been used. The model length was 1000 m, model width was 1000 m and the model thickness was 1000 m (ranging from top depth of 1000 m and bottom depth of 2000 m) with a regularly spaced grid of 15 × 15 × 48 grid (10800 gridblocks). The developed reservoir simulation model consists of two main regions which are reservoir rock region (sandstone) and cap rock region (shale). The simulated sandstone formation consists of quartz, kaolinite, chlorite, and illite. Our results show that CO2 injection leads to significant mineral reactionس (dissolution and precipitation) in the sandstone reservoir. Furthermore, the results indicate that these mineral reactions lead to increase in the sandstone porosity and permeability during the storage period. Thus, we conclude that the mineral reactions (dissolution and precipitation) due to CO2 injection in the sandstone reservoir affect the sandstone porosity and permeability, and hence, affect the CO2 geological storage capacity.

Wettability of CO2–water– reservoir rock system is a key factor to determine fluid dynamic and storage capacities in CO2 geo-storage process. Despite the past researches on this matter, the parameters that influence the CO2–water–rock wettability variation are still not fully understood. One of these parameters is rock-total organic content (TOC). Thus, here, we investigated the effect of TOC on the CO2–water–sandstone wettability and the implication for CO2 geo-storage at relevant reservoir conditions. The used sandstone samples were retrieved from the South West Hub CO2 capture and storage project (GSWA Harvey 1) in Western Australia. Here, we measured the contact angles for a range of sandstone TOC (i.e. 0.01 wt %, 0.015 wt %, 0.017 wt %, and 0.019 wt % TOC) at various pressures (5 MPa, 10 MPa, 15 MPa, and 20 MPa) and at an isothermal reservoir temperature (334 K). The results indicate that both of the advancing (θa) and receding (θr) contact angles for all tested sandstones increased with an increase in pressure TOC, implying the system turned to be more CO2-wet (e.g. the advancing contact angle increased from 92° to 118° when the sandstone TOC increased from 0.01 wt % to 0.019 wt %, at 20 MPa and reservoir temperature). Furthermore, our results indicate that the sandstone contact angle increase with pressure for all tested TOC values. Thus, we conclude that minute increasing in TOC can increase the sandstone contact angle and thus decrease the residual trapping capacities. Our results suggest that the contact angle measurement of rock retrieved from reservoirs should be treated properly for TOC to have an accurate estimation for the CO2 storage capacity.

CO2 capture and storage (CCS) is an important method to mitigate greenhouse gas (GHG) emissions by injecting CO2 into deep geological formations such as depleted hydrocarbon, unminable coal beds, and deep saline aquifers. However, due to the density variations between the supercritical CO2 and formation water, CO2 migrates upwards to the atmosphere. The risk of this CO2 migration can be prevented by different trapping mechanisms (e.g. structural trapping, capillary trapping, dissolution trapping, and mineral trapping). The trapping efficiency of these trapping mechanisms is highly influenced by various factors including CO2 injection scenarios, injection well configuration, reservoir wettability, reservoir heterogeneity, reservoir temperature, and formation water salinity. One of these factors, which has received little attention, is the caprock type. Although caprock wettability has been investigated previously as a factor affecting residual and structural trapping capacities, the effect of caprock type on mineral trapping efficiency has not been addressed yet. Thus, in this paper, we studied the impact of caprock type on geochemical reactivity and mineral trapping capacity by simulating a permeable sand reservoir overlying by three different semi-permeable caprock layers with different mineralogy (i.e. sandstone, siltstone, and shale). The Chemical Composition of these different caprock samples was measured using quantitative X-ray diffraction (XRD) instrument. XRD results indicated that siltstone and sandstone samples consisted mainly of quartz (~50wt %), while shale sample consisted mainly of illite (33)% and quartz (31%), in addition to few other smaller fractions of Illite, Chlorite, Albite, K-feldspar, Hematite, Ankerite, and Calcite. Our simulation results show that caprock type has a significant effect on geochemical reactivity and the associated mineral trapping mechanism. The results clearly indicate that the geochemical reactivity of siltstone caprock is relatively high, compared to shale and sandstone caprock cases. Furthermore, the results show that siltstone caprock scenario has the highest mineral trapping capacity, followed by shale and sandstone caprock scenarios, respectively. Moreover, the results indicate that sandstone caprock has the most increase in reservoir porosity and permeability. Thus, we conclude that the caprock mineral composition plays important roles in the geochemical reactivity and the associated mineral trapping of CO2.

Surfaces heterogeneity is a well-investigated fact and it represents a fundamental characteristic of the rock surfaces. Many factors are responsible for this surfaces heterogeneity such as the existence of impurities, surface roughness, the arrangement of the local crystalline, and the variation in crystal faces. Although the presence of clay minerals heterogeneity has been proven previously, its effect on the wettability measurements and the CO2 storage capacity has not been studied yet. Thus, in this paper, we therefore systematically measured the contact angle (wettability) of pure clay minerals (i.e. montmorillonite, illite and kaolinite) and mixed clay mineral (i.e. 14 wt% kaolinite, 48 wt% illite and 38 wt% montmorillonite) for CO2/brine systems. For both pure and mixed clay minerals, advancing and receding contact angles were measured at various pressures (5 MPa, 10 MPa, 15 MPa and 20 MPa) and temperatures (305 K and 333 K). The results show that clay minerals heterogeneity has a significant effect on the wettability measurements. The contact angles increase with increasing pressure for both pure clays and mixed clay. However, there is a slight increase in contact angles of pure clays as the pressure increases, compared to the mixed clay. For instance, the advancing contact angles have been increased from 77⁰ to 110⁰, 53⁰ to 67⁰, and 41⁰ to 57⁰ for pure montmorillonite, illite and kaolinite, respectively, by increasing the pressure from 5 MPa to 20 MPa. Meanwhile, the contact angle of mixed clay has been increased from 47⁰ to 93⁰ (i.e. the wettability of the mixed clay minerals has been altered from weakly water-wet to intermediate-wet) at the same pressures increase (from 5 MPa to 20 MPa). Furthermore, the results illustrate that the contact angle of both pure and mixed clay slightly reduce with increasing temperature from 305 K and 333 K. Thus, we conclude that clay minerals heterogeneity affects the clay wettability and leads to increase the contact angle at high pressures. Consequently, clay minerals heterogeneity reduce the CO2 storage capacity and containment security at high pressures. This study has important implications for deep geological carbon sequestration, CO2 dynamics and spreading in the geological reservoir.

The advanced low salinity aqueous formulations are yet to be validated as an injection fluid for enhanced oil recovery (EOR) from the carbonate reservoirs and COThis study, carried out for the first time in low salinity at scCOThis study reveals that a low dosage (100 mg/L) of ZrO