Solid/CO2 and solid/water interfacial tensions as a function of pressure, temperature, salinity and mineral type: Implications for CO2-wettability and CO2 geo-storage

Wettability of CO2/brine/mineral systems plays a significant role in the underground geological storage of CO2 as it governs the fluid flow and distribution mechanism within the porous medium. Technically, wettability is influenced by CO2 pressure, the temperature of the storage formation, formation water salinity and the type of mineral under investigation. Although a growing number of studies report wettability data for CO2/water/mineral systems, yet the factors responsible for wettability variation with pressure and temperature remain unclear. In this work, we used the concept of surface energy to explain dependency of wettability on pressure, temperature and salinity. Neumann's equation of state approach was used to compute solid/CO2 and solid/water interfacial energies using reliable contact angle and CO2/brine interfacial tension data from the literature at a wide range of operating conditions for quartz, water-wet mica, oil-wet mica and high, medium and low-rank coals. Moreover, the all-important question that why different minerals offer different wettability to CO2/water systems at the same pressure and temperature of investigation is addressed by comparing the interfacial energies of the minerals. We found that for all minerals solid/CO2 interfacial energy decreased with pressure and increased with temperature, and solid/water interfacial energy decreased with temperature except for quartz for which solid/water interfacial energy increased with temperature. Furthermore, the solid/CO2 interfacial energy was lowest for the oil-wet mica surface and highest for quartz which is due to higher hydrophobicity of oil-wet mica surface. The results of the study lead to a better understanding of the wetting phenomenon at the CO2/brine/mineral interface and thus contribute towards the better evaluation of geological CO2-storage processes

Degradation and hydrate phase equilibria measurement methods of monoethylene glycol

Monoethylene glycol (MEG), a common chemical used for the inhibition of gas hydrate formation may undergo degradation in the regeneration/reclamation process. Limited research exists on the effect of degradation of MEG on hydrate formation, production facilities and equipment especially in the presence of other chemical additives. The proposed method allows for streamlining the process of preparing, degrading and analysis of MEG solutions for hydrate testing and degradation products. • Procedure to prepare accurate MEG solutions avoiding oxidative degradation of MEG (i.e., controlling oxygen ingress).• Two methods are suggested to mimic field-like degradation of MEG solutions (i.e., degradation by reclamation and autoclave).• Adoption of the isochoric hydrate testing method while using a high pressure cell with the aid of a computer script to accurately evaluate hydrate phase equilibria conditions

Influence of surface chemistry on interfacial properties of low to high rank coal seams

Wettability of CO2/water/coal systems is a fundamental petro-physical parameter, which governs the fluid flow and distribution in coal seams and thus directly affects CO2-storage and methane recovery from unmineable coal seams. The recognition of wettability of coal/CO2/brine systems help to de-risk CO2-storage and enhanced methane recovery projects in coal seams. To understand the factors influencing the wetting characteristics of coals, a detailed examination and characterization of coal surface chemistry is essential and literature data in this context is missing. We thus measured zeta potentials as a function of temperature (298–343 K), brine salinity (0 wt% NaCl–5 wt% NaCl) and salt type (NaCl, CaCl2 and MgCl2) for coals of low, medium and high ranks. Further, we measured water advancing and receding contact angles as a function of temperature and salinity for the same experimental matrix in order to associate wettability changes to the surface charge at the coal/brine interface. Moreover, coal surfaces were investigated by Fourier transformed infrared (FTIR) spectroscopy and the surface functional groups responsible for a particular wetting behaviour were identified. We found that zeta potential increased with temperature, salinity and cation valency. Both advancing and receding contact angles decreased with temperature, and increased with salinity and cation valency irrespective of the coal rank. Finally the XRD measurements and infrared spectra revealed that the presence of polar surface functional groups (e.g. Si OH and carboxylic acid groups) which is responsible for the hydrophilic behaviour of low rank coals and the absence of these groups in high rank coal is responsible for their hydrophobic behaviour even at lower pressure. The high rank coal seams at high pressure are better for CO2 storage and methane recovery

Nanofluids as Novel Alternative Smart Fluids for Reservoir Wettability Alteration

This chapter presents an account of two metal oxide nanoparticles (zirconium and nickel oxide) on basis of their structure, morphology, crystallinity phases, and their wetting effect on solid-liquid interface. As a preliminary step to sound understanding of process mechanisms; wettability, nanoparticles, and their relations thereof were scrutinized. To investigate the nanofluids wetting inclinations, complex mixtures of the nanoparticles and NaCl brine (ZrO2/NaCl; NiO/NaCl) were formulated and their technical feasibility as wetting agents tested via contact angle measurement. The result shows that the nanoparticles exhibit different structural and morphological features and capable of addressing reservoir wettability challenges owing to favorable adsorption behavior on the surface of the calcite which facilitated the wetting changes quantified by contact angle. We believe this study will significantly impact the understanding of wetting at solid-liquid interface which is crucial for recovery process optimization

A case study: Application of energy and exergy analysis for enhancing the process efficiency of a three stage propane pre-cooling cycle of the cascade LNG process

The propane pre-cooling cycle has been widely used in most LNG plants as the first cooling cycle in the natural gas liquefaction process. As LNG plants consume high amounts of energy, enhancements in the process design and plant operation will minimize the overall energy consumption of the plant. The aim of this study is to enhance the process efficiency of a three stage propane pre-cooling cycle of the Cascade LNG process for the large-scale LNG train by determining the optimal operating conditions of the propane evaporator that will minimize the overall energy consumption. Energy and exergy analysis methods are adopted to evaluate the process efficiency of the propane pre-cooling cycle. Six case studies were presented to determine the optimal operating conditions of the propane evaporator that gives maximum energy reduction. The propane pre-cooling cycle is modelled and simulated using Aspen HYSYS with detailed thermodynamic information obtained to calculate the exergy loss. The results of the energy and exergy analysis indicate that Case 6 gives the highest coefficient of performance (COP) and the maximum exergy efficiency compared to the baseline case, which are 15.51% and 18.76% respectively. The results indicate that by reducing the cooling duty at the intermediate stages of propane evaporator about 13.5% energy saving can be achieved compared to the baseline case

Experimental determination of hydrate phase equilibrium for different gas mixtures containing methane, carbon dioxide and nitrogen with motor current measurements

Hydrate dissociation equilibrium conditions for carbon dioxide + methane with water, nitrogen + methane with water and carbon dioxide + nitrogen with water were measured using cryogenic sapphire cell. Measurements were performed in the temperature range of 275.75 K–293.95 K and for pressures ranging from 5 MPa to 25 MPa. The resulting data indicate that as the carbon dioxide concentration is increased in the gas mixture, the gas hydrate equilibrium temperature increases. In contrast, by increasing the nitrogen concentration in the gas mixtures containing methane or carbon dioxide decreased the gas hydrate equilibrium temperatures. Furthermore, the cage occupancies for the carbon dioxide + methane system were evaluated using the Van der Waals and Platteeuw thermodynamic theory with the Langmuir adsorption model and Peng-Robinson equation of state. The data demonstrated the increasing promoting effect of carbon dioxide with its concentration. In addition, the motor current changes during the hydrate formation and dissociation processes were measured by keeping the rotation speed of the magnetic stirrer that was connected to a DC motor constant. The motor current measurements were reported and it showed that the hydrate plug formation and dissociation could be predicted by the changes in the motor current

Impact of nanoparticles on the CO2-brine interfacial tension at high pressure and temperature

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

The influence of corrosion inhibitors on hydrate formation temperature along the subsea natural gas pipelines

Pipeline industry annually invests millions of dollar on corrosion inhibitors in order to minimize corrosion׳s implication on flow assurance; however, attention has never been focused on the possibilities of these chemicals to promote hydrate formation along deepwater pipeline which is also a flow assurance problem. Five inhibitors were investigated in this study at different concentrations and pressures in a cryogenic sapphire cell at static condition. The changes in the formation temperature established that all the inhibitors promote hydrate but at different rates while their hydrate formation patterns also differ from one another. Their ability to promote hydrate could be attributed to their hydrogen bonding properties which is required for hydrate formation. Also, the difference in the promotion rate is attributed to their different sizes and structures, active functional groups and affinity for water molecules which determine the type of hydrogen bonding exhibited by each inhibitor while in solution. The structure and size of each inhibitor also affect its electronegativity and ionization energy since the active electrons of some of the inhibitors have direct exposure to the nucleus while for others; the active electrons at the outermost shell have been shielded from direct influence of the attractive force. Furthermore, the active functional groups obeys electronegativity trend of periodic table to determine whether the resulting bond type will be polar ionic, covalent or ionic with some covalent characteristic in nature. Though, all the inhibitors are foamy; dodecylpyridinium chloride (DPC) was however the foamiest. DPC also exhibited its highest promotion ability at 200 ppm and exhibited specific behaviour at 5000 ppm to suggest a change in the hydrate formation rate beyond the Critical Micelles Concentration (CMC). Again, increase in agitation rate prolonged the complete solidification time of the hydrates probably due to the gas solubility. Finally, the feasibility of using this chemical as an additive at high concentrations for natural gas transportation and storage in slurry form was observed due to some exhibited properties, this however requires further investigations

Wettability alteration of oil-wet limestone using surfactant-nanoparticle formulation

Wettability remains a prime factor that controls fluid displacement at pore-scale with substantial impact on multi-phase flow in the subsurface. As the rock surface becomes hydrophobic, any oleic phase present is tightly stored in the rock matrix and produced (hydrocarbon recovery) or cleaned up (soil-decontamination) by standard waterflooding methods. Although surface active agents such as surfactants have been used for several decades for changing the wetting states of such rocks, an aspect that has been barely premeditated is the simultaneous blends of surfactants and nanoparticles. This study thus, systematically reports the behaviour of surfactants augmented nanoparticles on wettability alteration. Contact angle, spontaneous imbibition, and mechanistic approaches were adopted to assess the technical feasibility of the newly formulated wetting agents, tested over wide-ranging conditions to ascertain efficient wetting propensities. The contact angle measurement is in good agreement with the morphological and topographical studies and spontaneous imbibition. The wetting trends for the formulated systems indicate advancing and receding water contact angle decreased with increase in nanoparticle concentration and temperature, and the spontaneous water imbibition test also showed faster water-imbibing tendencies for nanoparticle-surfactant exposed cores. Thus, the new formulated nanoparticle-surfactant systems were considered suitable for enhancing oil recovery and soil-decontamination, particularly in fractured hydrophobic reservoirs

A Realistic Look at Nanostructured Material as an Innovative Approach for Enhanced Oil Recovery Process Upgrading

With the continuous rise in energy demand and decline in reserves, the Petroleum Industries are constantly in search of inventive and novel approaches to optimize hydrocarbon recovery despite several decades of deployment of conventional and enhanced strategies. This chapter presents an in-depth analysis of nanomaterial (nanoparticles), their unique characteristics and potentials in relation to smart field development, enhanced oil recovery (EOR) and CO2 geosequestration. The particles surface functionalities, unique size dependent property, adsorption, and transport behavior were scrutinized. The materials precise role in enhancing reservoir parameters that influences rock–fluid interactions, and reservoir fluid distribution and displacement such as permeability, wettability, interfacial tension, and asphaltene aggregate growth inhibition were evaluated. The study argues that the application of nanoparticle based fluids as novel EOR approach offers more holistic measures, potentials, and opportunities than micro and macro particles and can stimulate the continuous evolution of EOR processes even under harsh reservoir conditions, thus, offering better benefits over conventional surface-active agents. We believe this study will significantly impact the understanding of EOR with respect to nanoparticles, which is crucial for augmenting reservoir processes and to accelerate the realization of nanoparticles for EOR and CO2 sequestration processes at industrial scale