Organic acid concentration thresholds for ageing of carbonate minerals: Implications for CO2 trapping/storage

Evaluation of rock and fluid intermolecular interaction between asphaltene and sand minerals using electrochemical, analytical spectroscopy and microscopy techniques

Long-time contact of heavy crude oil with rock leads to an adsorption phenomenon, which causes the rock surface to become oil-wet and appears as a barrier to the fluid flow in the porous media. However precise understanding of how asphaltene fractions influence sand wettability is lacking. The wetness of neat and asphaltene-aged sandstone was calculated using two relative permeability and contact angle methods. Then the molecular interaction between asphaltene and sand minerals was systematically analyzed using Fourier-transform infrared spectroscopy. Furthermore, the zeta potential was representative of electrostatic properties and surface charge alteration of the sand after these phenomena. Scanning electron microscopy with energy-dispersive X-ray (EDX) analysis also showed elemental mapping and dispersion of asphaltene particles on the rock surface. According to contact angle and EDX analyses of asphaltene samples, the contact angle rises from 115° to 141° by an increase in carbon adsorption on the sand surface from 8.23 to 41.56%. Spectroscopy results demonstrated that hydrogen-bonding, π-bonding, and sulfur-containing compounds such as sulfoxide improve asphaltene adsorption onto the sand surface. The higher the aromaticity index and hydrogen potential index of asphaltene, the greater the ability of asphaltene to change wettability. Adsorption of surface active components would make the surface charge of the sand more negative. The presence of nitrogen/sulfur-containing functional groups on the sand surface changed the electrostatic properties, as a sand surface coated with asphaltene would reduce the percentage of metal cations.

Impact of Methylene Blue on Enhancing the Hydrocarbon Potential of Early Cambrian Khewra Sandstone Formation from the Potwar Basin, Pakistan

Significant amounts of hydrocarbon resources are left behind after primary and secondary recovery processes, necessitating the application of enhanced oil recovery (EOR) techniques for improving the recovery of trapped oil from subsurface formations. In this respect, the wettability of the rock is crucial in assessing the recovery and sweep efficiency of trapped oil. The subsurface reservoirs are inherently contaminated with organic acids, which renders them hydrophobic. Recent research has revealed the significant impacts of nanofluids, surfactants, and methyl orange on altering the wettability of organic-acid-contaminated subsurface formations into the water-wet state. This suggests that the toxic dye methylene blue (MB), which is presently disposed of in huge quantities and contaminates subsurface waters, could be used in EOR. However, the mechanisms behind hydrocarbon recovery using MB solution for attaining hydrophilic conditions are not fully understood. Therefore, the present work examines the impacts of MB on the wettability reversal of organic-acid-contaminated Khewra sandstone samples (obtained from the outcrop in the Potwar Basin, Pakistan) under the downhole temperature and pressure conditions. The sandstone samples are prepared by aging with 10-2 mol/L stearic acid and subsequently treated with various amounts of aqueous MB (10-100 mg/L) for 1 week. Contact angle measurements are then conducted under various physio-thermal conditions (0.1-20 MPa, 25-50 °C, and salinities of 0.1-0.3 M). The results indicate that the Khewra sandstone samples become hydrophobic in the presence of organic acid and under increased pressure, temperature, and salinity. However, the wettability changes from oil-wet to preferentially water-wet in the presence of various MB solutions, thus highlighting the favorable effects of MB on EOR from the Khewra sandstone formation. Moreover, the most significant change in wettability is observed for the Khewra sandstone sample that was aged using 100 mg/L MB. These results suggest that injecting MB into deep underground Khewra sandstone reservoirs may produce more residual hydrocarbons.

Enhancing the CO2 trapping capacity of Saudi Arabian basalt via nanofluid treatment: Implications for CO2 geo-storage

Mineralization reactions in basaltic formations have gained recent interest as an effective method for CO₂ geo-storage in order to mitigate anthropogenic greenhouse gas emissions. The CO₂/rock interactions, including interfacial tension and wettability, are crucial factors in determining the CO₂ trapping capacity and the feasibility of CO₂ geological storage in these formations. The Red Sea geological coast in Saudi Arabia has many basaltic formations, and their wetting characteristics are rarely reported in the literature. Moreover, organic acid contamination is inherent in geo-storage formations and significantly impacts their CO₂ geo-storage capacities. Hence, to reverse the organic effect, the influence of various SiO₂ nanofluid concentrations (0.05-0.75 wt%) on the CO₂-wettability of organic-acid aged Saudi Arabian (SA) basalt is evaluated herein at 323 K and various pressures (0.1-20 MPa) via contact angle measurements. The SA basalt substrates are characterized via various techniques, including atomic force microscopy, energy dispersive spectroscopy, scanning electron microscopy, and others. In addition, the CO₂ column heights that correspond to the capillary entry pressure before and after nanofluid treatment are calculated. The results show that the organic acid-aged SA basalt substrates become intermediate-wet to CO₂-wet under reservoir pressure and temperature conditions. When treated with SiO₂ nanofluids, however, the SA basalt substrates become weakly water-wet, and the optimum performance is observed at an SiO₂ nanofluid concentration of 0.1 wt%. At 323 K and 20 MPa, the CO₂ column height corresponding to the capillary entry pressure increases from -957 m for the organic-aged SA basalt to 6253 m for the 0.1 wt% nano-treated SA basalt. The results suggest that the CO₂ containment security of organic-acid-contaminated SA basalt can be enhanced by SiO₂ nanofluid treatment. Thus, the results of this study may play a significant role in assessing the trapping of CO₂ in SA basaltic formations.

Influence of stearic acid and alumina nanofluid on CO2 wettability of calcite substrates: Implications for CO2 geological storage in carbonate reservoirs

HYPOTHESIS

Atmospheric CO₂ emissions trigger global warming and climate change challenges. Thus, geological CO₂ storage appears to be the most viable choice to mitigate CO₂ emissions in the atmosphere. However, the adsorption capacity of reservoir rock in the presence of diverse geological conditions, including organic acids, temperature, and pressure, can cause reduced certainty for CO₂ storage and injection problems. Wettability is critical in measuring the adsorption behavior of rock in various reservoir fluids and conditions.

EXPERIMENT

We systematically evaluated the CO₂-wettability of calcite substrates at geological conditions (323 K and 0.1, 10, and 25 MPa) in the presence of stearic acid (a replicate realistic reservoir organic material contamination). Similarly, to reverse the effects of organics on wettability, we treated calcite substrates with various alumina nanofluid concentrations (0.05, 0.1, 0.25, and 0.75 wt%) and evaluated the CO₂-wettability of calcite substrates at similar geological conditions.

FINDINGS

Stearic acid profoundly affects the contact angle of calcite substrates where wettability shifts from intermediate to CO₂-wet conditions, reducing the CO₂ geological storage potential. The treatment of organic acid-aged calcite substrates with alumina nanofluid reversed the wettability to a more hydrophilic state, increasing CO₂ storage certainty. Further, the optimum concentration displaying the optimum potential for changing the wettability in organic acid-aged calcite substrates was 0.25 wt%. The effect of organics and nanofluids should be augmented to improve the feasibility of CO₂ geological projects at the industrial scale for reduced containment security.

Impact of injection temperature and formation slope on CO2 storage capacity and form in the Ordos Basin, China

Carbon dioxide (CO2) storage capacity is the main criterion for assessing CO2 geological storage. Based on actual data from the Shiqianfeng formation in the Ordos Basin, three-dimensional (3D) models were built using the TOUGHVISUAL visualization software and simulated using the TOUGH2 integral finite difference modeling code with the ECO2N fluid property module to explore the impact of formation attributes (formation slope) and controllable factors (injection temperature) on CO2 storage capacity. A total of 16 schemes were designed, with four injection temperatures (24 ℃, 31 ℃, 38 ℃, and 45 ℃) and four formation slopes (0°, 5°, 10°, and 15°). Simulation results showed that the injection temperature and formation slope both had a significant influence on CO2 storage capacity. The impact of injection temperature on the total storage amount was more obvious than that of the impact of formation slope. A higher injection temperature resulted in a greater total storage amount. Increasing the formation slope and injection temperature increased the gas-phase, dissolved-phase, and total CO2 storage amounts in the upper left section of the injection well, but decreased them in the lower right part of the injection well. The impact of formation slope on the conversion rate from gas-phase CO2 to dissolved-phase CO2 was more obvious than the impact of injection temperature. A steeper formation slope resulted in a higher conversion rate. A smaller formation slope and a higher injection temperature should be selected to store CO2.

Live imaging of micro and macro wettability variations of carbonate oil reservoirs for enhanced oil recovery and CO2 trapping/storage

Carbonate hydrocarbon reservoirs are considered as potential candidates for chemically enhanced oil recovery and for CO₂ geological storage. However, investigation of one main controlling parameter-wettability-is usually performed by conventional integral methods at the core-scale. Moreover, literature reports show that wettability distribution may vary at the micro-scale due to the chemical heterogeneity of the reservoir and residing fluids. These differences may profoundly affect the derivation of other reservoir parameters such as relative permeability and capillary pressure, thus rendering subsequent simulations inaccurate. Here we developed an innovative approach by comparing the wettability distribution on carbonates at micro and macro-scale by combining live-imaging of controlled condensation experiments and X-ray mapping with sessile drop technique. The wettability was quantified by measuring the differences in contact angles before and after aging in palmitic, stearic and naphthenic acids. Furthermore, the influence of organic acids on wettability was examined at micro-scale, which revealed wetting heterogeneity of the surface (i.e., mixed wettability), while corresponding macro-scale measurements indicated hydrophobic wetting properties. The thickness of the adsorbed acid layer was determined, and it was correlated with the wetting properties. These findings bring into question the applicability of macro-scale data in reservoir modeling for enhanced oil recovery and geological storage of greenhouse gases.

Influence of organic molecules on wetting characteristics of mica/H2/brine systems: Implications for hydrogen structural trapping capacities

HYPOTHESIS

Actualization of the hydrogen (H₂) economy and decarbonization goals can be achieved with feasible large-scale H₂ geo-storage. Geological formations are heterogeneous, and their wetting characteristics play a crucial role in the presence of H₂, which controls the pore-scale distribution of the fluids and sealing capacities of caprocks. Organic acids are readily available in geo-storage formations in minute quantities, but they highly tend to increase the hydrophobicity of storage formations. However, there is a paucity of data on the effects of organic acid concentrations and types on the H₂-wettability of caprock-representative minerals and their attendant structural trapping capacities.

EXPERIMENT

Geological formations contain organic acids in minute concentrations, with the alkyl chain length ranging from C₄ to C₂₆. To fully understand the wetting characteristics of H₂ in a natural geological picture, we aged mica mineral surfaces as a representative of the caprock in varying concentrations of organic molecules (with varying numbers of carbon atoms, lignoceric acid C₂₄, lauric acid C₁₂, and hexanoic acid C₆) for 7 days. To comprehend the wettability of the mica/H₂/brine system, we employed a contact-angle procedure similar to that in natural geo-storage environments (25, 15, and 0.1 MPa and 323 K).

FINDINGS

At the highest investigated pressure (25 MPa) and the highest concentration of lignoceric acid (10^-2 mol/L), the mica surface became completely H₂ wet with advancing (θ_a= 106.2°) and receding (θ_r=97.3°) contact angles. The order of increasing θ_a and θ_r with increasing organic acid contaminations is as follows: lignoceric acid > lauric acid > hexanoic acid. The results suggest that H₂ gas leakage through the caprock is possible in the presence of organic acids at higher physio-thermal conditions. The influence of organic contamination inherent at realistic geo-storage conditions should be considered to avoid the overprediction of structural trapping capacities and H₂ containment security.

Underground hydrogen storage: Influencing parameters and future outlook

Underground hydrogen storage (UHS) is a promising technology with which large quantities of H₂ can potentially be stored in the subsurface safely, economically and efficiently. As UHS is a relatively new technology, we critically reviewed all available data related to solid properties, fluid properties and solid-fluid interactions relevant to UHS. We also provide clear conclusions, and highlight research gaps. This review therefore advances fundamental understanding of UHS at multiple physical scales and provides key guidance for UHS project operations at reservoir scale.

Western Australia basalt-CO2-brine wettability at geo-storage conditions

HYPOTHESIS

CO₂ geo-storage is a technique, where millions of tonnes of CO₂ are stored in underground formations every year for permanent immobilization to reduce greenhouse gas emissions. Among promising geo-storage formations, basalt is attracting keen interest from researchers and industry. However, the literature severely lacks information on the wetting behaviour of basaltic rocks at geo-storage conditions.

EXPERIMENTS

To enable a more general statement of basalt-scCO₂-brine contact angles, the wettability of a basalt from Western Australia was compared with a similar rock type from Iceland. This study reports the advancing and receding contact angles for a basalt-scCO₂-brine system at pressures ranging from 0.1 to 20 MPa and temperatures of 298 and 323 K, respectively. Based on the experimental data, the amount of CO₂, expressed by the column height, which could be safely trapped beneath the basalt was then calculated.

FINDINGS

The basalt was initially water-wet but with increasing pressure, it was converted sequentially from a water-wet to an intermediate-wet and then finally into a completely CO₂-wet template at pressures exceeding 15 MPa and 323 K. Under those experimental conditions, found in the field at depths below 1500 m, injected supercritical CO₂ into a porous basalt reservoir is assumed to flow freely in lateral and vertical directions and is less impeded by capillary/residual trapping, potentially leading to CO₂ leakage. It is suggested that the injection depth should not be chosen too deep to avoid increased free CO₂ plume mobility. It is found from CO₂ column height calculations that at 800 m depth (a minimum requirement to keep CO₂ supercritical), the height of the CO₂ column that can be safely trapped below the cap rock, was still 100 m but shrank to nil at ≥1500 m.

Tuning Surface Chemistry and Ionic Strength to Control Nanoparticle Adsorption and Elastic Dilational Modulus at Air-Brine Interface

The relationship between the interfacial rheology of nanoparticle (NP) laden air-brine interfaces and NP adsorption and interparticle interactions is not well understood, particularly as a function of the surface chemistry and salinity. Herein, a nonionic ether diol on the surface of silica NPs provides steric stabilization in bulk brine and at the air-brine interface, whereas a second smaller underlying hydrophobic ligand raises the hydrophobicity to promote NP adsorption. The level of NPs adsorption at steady state is sufficient to produce an interface with a relatively strong elastic dilational modulus E' = dγ/d ln A. However, the interface is ductile with a relatively slow change in E' as the interfacial area is varied over a wide range during compression and expansion. In contrast, for silica NPs stabilized with only a single hydrophobic ligand, the interfaces are often more fragile and may fracture with small changes in area. The presence of concentrated divalent cations improves E' and ductility by screening electrostatic dipolar repulsion and strengthening the attractive forces between nanoparticles. The ability to tune the interfacial rheology with NP surface chemistry is of great interest for designing more stable gas/brine foams.

Interaction of low salinity surfactant nanofluids with carbonate surfaces and molecular level dynamics at fluid-fluid interface at ScCO2 loading

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.

In Situ Wettability Investigation of Aging of Sandstone Surface in Alkane via X-ray Microtomography

Wettability of surfaces remains of paramount importance for understanding various natural and artificial colloidal and interfacial phenomena at various length and time scales. One of the problems discussed in this work is the wettability alteration of a three-phase system comprising high salinity brine as the aqueous phase, Doddington sandstone as porous rock, and decane as the nonaqueous phase liquid. The study utilizes the technique of in situ contact angle measurements of the several 2D projections of the identified 3D oil phase droplets from the 3D images of the saturated sandstone miniature core plugs obtained by X-ray microcomputed tomography (micro-CT). Earlier works that utilize in situ contact angles measurements were carried out for a single plane. The saturated rock samples were scanned at initial saturation conditions and after aging for 21 days. This study at ambient conditions reveals that it is possible to change the initially intermediate water-wet conditions of the sandstone rock surface to a weakly water wetting state on aging by alkanes using induced polarization at the interface. The study adds to the understanding of initial wettability conditions as well as the oil migration process of the paraffinic oil-bearing sandstone reservoirs. Further, it complements the knowledge of the wettability alteration of the rock surface due to chemisorption, usually done by nonrepresentative technique of silanization of rock surface in experimental investigations.

Influence of Organic Acid Concentration on Wettability Alteration of Cap-Rock: Implications for CO2 Trapping/Storage

Every year, millions of tons of CO₂ are stored in CO₂-storage formations (deep saline aquifers) containing traces of organic acids including hexanoic acid C₆ (HA), lauric acid C₁₂ (LuA), stearic acid C₁₈ (SA), and lignoceric acid C₂₄ (LiA). The presence of these molecules in deep saline aquifers is well documented in the literature; however, their impact on the structural trapping capacity and thus on containment security is not yet understood. In this study, we therefore investigate as to how an increase in organic acid concentration can alter mica water wettability through an extensive set of experiments. X-ray diffraction (Figure S2), field emission scanning electron microscopy, total organic carbon analysis, Fourier-transform infrared spectroscopy, atomic force microscopy, and energy-dispersive X-ray spectroscopy were utilized to perceive the variations in organic acid surface coverage with stepwise organic acid concentration increase and changes in surface roughness. Furthermore, thresholds of wettability that may indicate limits for structural trapping potential (θ_r < 90°) have been discussed. The experimental results show that even a minute concentration (∼10^-5 mol/L for structural trapping) of lignoceric acid is enough to affect the CO₂ trapping capacity at 323 K and 25 MPa. As higher concentrations exist in deep saline aquifers, it is necessary to account for these thresholds to derisk CO₂-geological storage projects.

Effect of Environment-Friendly Non-Ionic Surfactant on Interfacial Tension Reduction and Wettability Alteration; Implications for Enhanced Oil Recovery

Production from mature oil reservoirs can be optimized by using the surfactant flooding technique. This can be achieved by reducing oil and water interfacial tension (IFT) and modifying wettability to hydrophilic conditions. In this study, a novel green non-ionic surfactant (dodecanoyl-glucosamine surfactant) was synthesized and used to modify the wettability of carbonate reservoirs to hydrophilic conditions as well as to decrease the IFT of hydrophobic oil–water systems. The synthesized non-ionic surfactant was characterized by Fourier transform infrared spectroscopy (FTIR) and chemical shift nuclear magnetic resonance (HNMR) analyses. Further pH, turbidity, density, and conductivity were investigated to measure the critical micelle concentration (CMC) of surfactant solutions. The result shows that this surfactant alters wettability from 148.93° to 65.54° and IFT from 30 to 14 dynes/cm. Core-flooding results have shown that oil recovery was increased from 40% (by water flooding) to 59% (by surfactant flooding). In addition, it is identified that this novel non-ionic surfactant can be used in CO2 storage applications due to its ability to alter the hydrophobicity into hydrophilicity of the reservoir rocks.

Nanomaterial-Based Drilling Fluids for Exploitation of Unconventional Reservoirs: A Review

The world’s energy demand is steadily increasing where it has now become difficult for conventional hydrocarbon reservoir to meet levels of demand. Therefore, oil and gas companies are seeking novel ways to exploit and unlock the potential of unconventional resources. These resources include tight gas reservoirs, tight sandstone oil, oil and gas shales reservoirs, and high pressure high temperature (HPHT) wells. Drilling of HPHT wells and shale reservoirs has become more widespread in the global petroleum and natural gas industry. There is a current need to extend robust techniques beyond costly drilling and completion jobs, with the potential for exponential expansion. Drilling fluids and their additives are being customized in order to cater for HPHT well drilling issues. Certain conventional additives, e.g., filtrate loss additives, viscosifier additives, shale inhibitor, and shale stabilizer additives are not suitable in the HPHT environment, where they are consequently inappropriate for shale drilling. A better understanding of the selection of drilling fluids and additives for hydrocarbon water-sensitive reservoirs within HPHT environments can be achieved by identifying the challenges in conventional drilling fluids technology and their replacement with eco-friendly, cheaper, and multi-functional valuable products. In this regard, several laboratory-scale literatures have reported that nanomaterial has improved the properties of drilling fluids in the HPHT environment. This review critically evaluates nanomaterial utilization for improvement of rheological properties, filtrate loss, viscosity, and clay- and shale-inhibition at increasing temperature and pressures during the exploitation of hydrocarbons. The performance and potential of nanomaterials, which influence the nature of drilling fluid and its multi-benefits, is rarely reviewed in technical literature of water-based drilling fluid systems. Moreover, this review presented case studies of two HPHT fields and one HPHT basin, and compared their drilling fluid program for optimum selection of drilling fluid in HPHT environment.

Wettability of rock/CO2/brine and rock/oil/CO2-enriched-brine systems:Critical parametric analysis and future outlook

CO₂ geo-sequestration is a promising technology to permanently store CO₂ in geological formations to control the atmospheric carbon footprint. In addition, CO₂ is frequently utilized in enhanced oil recovery operations to accelerate oil production. Both, CO₂ geo-storage and EOR, are significantly influenced by the wettability of the associated rock/CO₂/brine systems. Wettability drives the multiphase flow dynamics, and microscopic fluid distribution in the reservoir. Furthermore, while wettability is known to be influenced by varying in-situ conditions and surface chemistry of the rock/mineral, the current state-of-the-art indicates wider variabilities of the wetting states. This article, therefore, critically reviews the published datasets on CO₂ wettability of geological formations. Essentially, the rock/CO₂/brine and rock/crude-oil/CO₂-enriched-brine contact angle datasets for the important reservoir rocks (i.e. sandstone and carbonate rocks), as well as for the key minerals quartz and calcite are considered. Also, the parameters that influence wettability are critically analyzed, and the associated parametric trends are discussed and summarized. Finally, we identify pertinent research gaps and define the outlook of future research. The review, therefore, establishes a repository of the recent contact angle data, which thus assists to enhance our current understanding of the subject.

Application of the CLAYFF and the DREIDING Force Fields for Modeling of Alkylated Quartz Surfaces

To extend applicability and to overcome limitations of combining rules for nonbond potential parameters, in this study, CLAYFF and DREIDING force fields are coupled at the level of atomic site charges to model quartz surfaces with chemisorpt hydrocarbons. Density functional theory and Bader charge analysis are applied to calculate charges of atoms of the OC bond connecting a quartz crystal and an alkyl group. The study demonstrates that the hydrogen atom of the quartz surface hydroxyl group can be removed and its charge can be redistributed among the oxygen and carbon atoms of the OC bond in a manner consistent with the results calculated at the density functional level of theory. Augmented with modified charges of the OC bond, force fields can then be applied to a practical problem of evaluation of the contact angle of a water droplet on alkylated quartz surfaces in a carbon dioxide environment, which is relevant for carbon geo-sequestration and in a broader context of oil and gas recovery. Alkylated quartz surfaces have been shown to be extremely hydrophobic even when the surface density of hydroxyl groups is close to the highest naturally observed density of 6.2 OH groups per square nanometer.