Quantifying the Influence of Electrolytes on the Kinetics of Spontaneous Emulsification.

This study quantifies the influence of electrolytes on the kinetics of the spontaneous emulsification phenomenon (SEP) of heavy hydrocarbons in a nonionic surfactant solution. The rate of emulsifying hexadecane in Triton X-100, with the presence of sodium chloride and potassium chloride, has been measured using a technique of monitoring single oil droplet photography. The emulsion droplet size produced in the process was measured under the same conditions by using dynamic light scattering. The data obtained from the two experiments were employed to investigate the mass transfer coefficient of the surfactant molecules through the intermediate layer formed between hexadecane and the surfactant solution. It was found that the electrolytes in an aqueous solution increase the surfactant diffusion rate through the intermediate layer and reduce the emulsion droplet size. As a result, both electrolytes reduce the rate of spontaneous emulsification, with potassium chloride having a more substantial reduction. A model was developed to quantify the influence of electrolytes on the kinetics of the SEP. The data and modeling results verify the influence of ions on the kinetics of spontaneous emulsification. The results provide a significant foundation for predicting the solubilization of heavy hydrocarbons in an electrolyte solution.

COVID-19 and offshore oil and gas workers: The role of personality.

This qualitative study aimed to identify mental health hazards in the offshore oil and gas industry, as well as the role of the personality types of the Five Factor Model (FFM) in coping with these stressors. A focus group with 8 participants and a pilot study with 5 participants were conducted. Results showed that several stressors are currently present for Australian offshore oil and gas employees, in particular COVID-19 and the resulting negative effects on rosters, working hours, job security and time spent away from home. Other stressors revealed by participants were lack of space, working in a high-risk environment, stigma, helicopter travel and pressure to keep up with production. Poor safety behaviours were associated with neuroticism, extraversion and openness, while risk avoidance appear to be associated with agreeableness and conscientiousness. Tolerance to shift work was positively related to extraversion, yet negatively associated to neuroticism. Furthermore, neuroticism showed a negative association with help-seeking and productivity, as well as higher levels of concern relating to COVID-19 and job uncertainty. As personality traits are enduring throughout life, it is vital that employees are managed effectively through workplace interventions so that they are able to cope effectively, particularly during stressful events.

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.

Pore scale investigation of low salinity surfactant nanofluid injection into oil saturated sandstone via X-ray micro-tomography.

HYPOTHESIS: Low salinity surfactant nanofluids have recently shown promising characteristics in wettability alteration of the silicate-based rock representative substrate and interfacial tension reduction of oil/aqueous phase interface. Pore level understanding of the physical processes entailed in this new class of low salinity injection fluids in oil-phase saturated real rock porous media is required, which has not been conceived yet. EXPERIMENTS: Thus, we investigate the oil recovery performance and possible mechanisms of oil recovery by the injection of low salinity surfactant (SDBS, 1.435 mM) aqueous solutions (with 0%, 0.01% and 0.1% (by weight) ZrO2 nanoparticles) into the oil phase saturated Doddington sandstone miniature core plugs. The designed experiment involves core flooding with X-ray transparent core-holder developed in-house and analysis/processing of the acquired image data. FINDINGS: The injection of low salinity surfactant nanofluids with 0.01% ZrO2 nanoparticles leads to maximum oil phase recovery. The results suggest that the dominating mechanisms for oil recovery are wettability alteration, inherent interfacial tension reduction, and the effect of significant amount of microemulsions formation is rather trivial. Low salinity effect, even in combination with surfactant, caused fines migrations (not reported earlier), is found to be significantly mitigated using nanoparticles. This new class of fluids may significantly enhance oil recovery.

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.

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

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.

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.

Carbon dioxide/brine wettability of porous sandstone versus solid quartz: An experimental and theoretical investigation.

HYPOTHESIS: Wettability plays an important role in underground geological storage of carbon dioxide because the fluid flow and distribution mechanism within porous media is controlled by this phenomenon. CO2 pressure, temperature, brine composition, and mineral type have significant effects on wettability. Despite past research on this subject, the factors that control the wettability variation for CO2/water/minerals, particularly the effects of pores in the porous substrate on the contact angle at different pressures, temperatures, and salinities, as well as the physical processes involved are not fully understood. EXPERIMENTS: We measured the contact angle of deionised water and brine/CO2/porous sandstone samples at different pressures, temperatures, and salinities. Then, we compared the results with those of pure quartz. Finally, we developed a physical model to explain the observed phenomena. FINDINGS: The measured contact angle of sandstone was systematically greater than that of pure quartz because of the pores present in sandstone. Moreover, the effect of pressure and temperature on the contact angle of sandstone was similar to that of pure quartz. The results showed that the contact angle increases with increase in temperature and pressure and decreases with increase in salinity.

Removal of monoethylene glycol from wastewater by using Zr-metal organic frameworks.

Mono-ethylene glycol (MEG), used in the oil and gas industries as a gas hydrate inhibitor, is a hazardous chemical present in wastewater from those processes. Metal-organic frameworks (MOFs) (modified UiO-66∗ and UiO-66-2OH) were used for the effective removal of MEG waste from effluents of distillation columns (MEG recovery units). Batch contact adsorption method was used to study the adsorption behavior toward these types of MOFs. Adsorption experiments showed that these MOFs had very high affinity toward MEG. Significant adsorption capacity was demonstrated on UiO-66-2OH and modified UiO-66 at 1000 mg·g-1 and 800 mg·g-1 respectively. The adsorption kinetics were fitted to a pseudo first-order model. UiO-66-2OH showed a higher adsorption capacity due to the presence of hydroxyl groups in its structure. A Langmuir model gave the best fitting for isotherm of experimental data at pH = 7.

Influence of magnetic fields on calcium carbonate scaling in aqueous solutions at 150°C and 1bar.

The experiments performed as a part of this study were conducted to evaluate the effect of magnetic field treatment upon the scale forming tendency of brine solution composed primarily of calcium bicarbonate ions. The reported results were generated using a Dynamic Scale Loop system with the brine solution exposed to a magnetic field generated by a 6480 Gauss magnet of grade N45SH in a diametrical orientation for 2.5s. Following magnetic exposure, the brine solution was exposed to an elevated temperature 150°C at 1bar to promote the formation of scale within a capillary tube. The extent of scaling was measured by recording the differential pressure across the tube as scaling proceeded. Three important conclusions regarding the effect of magnetic field treatment upon scale formation in calcium bicarbonate solutions were reached. Firstly, the ratio of calcium to bicarbonate plays a key role in determining how magnetic fields influence scale formation, whether promoting or inhibiting it. Solutions containing high concentrations of the bicarbonate, or equal concentrations of the bicarbonate and calcium species showed inhibited scale formation following magnetic exposure. Secondly, the electrical conductivity of the calcium carbonate solution was noticeably impacted by the exposure to the magnetic field through manipulation of the ionic hydration shell and may also provide a measure of the extent of scale formation. Finally, the application of magnetic field treatment for scale inhibition may provide an alternative eco-friendly scale inhibition strategy in place of traditional chemical scale inhibitors.

Stabilising nanofluids in saline environments.

Nanofluids (i.e. nanoparticles dispersed in a fluid) have tremendous potential in a broad range of applications, including pharmacy, medicine, water treatment, soil decontamination, or oil recovery and CO2 geo-sequestration. In these applications nanofluid stability plays a key role, and typically robust stability is required. However, the fluids in these applications are saline, and no stability data is available for such salt-containing fluids. We thus measured and quantified nanofluid stability for a wide range of nanofluid formulations, as a function of salinity, nanoparticle content and various additives, and we investigated how this stability can be improved. Zeta sizer and dynamic light scattering (DLS) principles were used to investigate zeta potential and particle size distribution of nanoparticle-surfactant formulations. Also scanning electron microscopy was used to examine the physicochemical aspects of the suspension. We found that the salt drastically reduced nanofluid stability (because of the screening effect on the repulsive forces between the nanoparticles), while addition of anionic surfactant improved stability. Cationic surfactants again deteriorated stability. Mechanisms for the different behaviour of the different formulations were identified and are discussed here. We thus conclude that for achieving maximum nanofluid stability, anionic surfactant should be added.

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.

Residual trapping of supercritical CO2 in oil-wet sandstone.

Residual trapping, a key CO2 geo-storage mechanism during the first decades of a sequestration project, immobilizes micrometre sized CO2 bubbles in the pore network of the rock. This mechanism has been proven to work in clean sandstones and carbonates; however, this mechanism has not been proven for the economically most important storage sites into which CO2 will be initially injected at industrial scale, namely oil reservoirs. The key difference is that oil reservoirs are typically oil-wet or intermediate-wet, and it is clear that associated pore-scale capillary forces are different. And this difference in capillary forces clearly reduces the capillary trapping capacity (residual trapping) as we demonstrate here. For an oil-wet rock (water contact angle θ=130°) residual CO2 saturation SCO2,r (≈8%) was approximately halved when compared to a strongly water-wet rock (θ=0°; SCO2,r≈15%). Consequently, residual trapping is less efficient in oil-wet reservoirs.

Wettability alteration of oil-wet carbonate by silica nanofluid.

Changing oil-wet surfaces toward higher water wettability is of key importance in subsurface engineering applications. This includes petroleum recovery from fractured limestone reservoirs, which are typically mixed or oil-wet, resulting in poor productivity as conventional waterflooding techniques are inefficient. A wettability change toward more water-wet would significantly improve oil displacement efficiency, and thus productivity. Another area where such a wettability shift would be highly beneficial is carbon geo-sequestration, where compressed CO2 is pumped underground for storage. It has recently been identified that more water-wet formations can store more CO2. We thus examined how silica based nanofluids can induce such a wettability shift on oil-wet and mixed-wet calcite substrates. We found that silica nanoparticles have an ability to alter the wettability of such calcite surfaces. Nanoparticle concentration and brine salinity had a significant effect on the wettability alteration efficiency, and an optimum salinity was identified, analogous to that one found for surfactant formulations. Mechanistically, most nanoparticles irreversibly adhered to the oil-wet calcite surface (as substantiated by SEM-EDS and AFM measurements). We conclude that such nanofluid formulations can be very effective as enhanced hydrocarbon recovery agents and can potentially be used for improving the efficiency of CO2 geo-storage.

Impact of pressure and temperature on CO2-brine-mica contact angles and CO2-brine interfacial tension: Implications for carbon geo-sequestration.

Precise characterization of wettability of CO2-brine-rock system and CO2-brine interfacial tension at reservoir conditions is essential as they influence capillary sealing efficiency of caprocks, which in turn, impacts the structural and residual trapping during CO2 geo-sequestration. In this context, we have experimentally measured advancing and receding contact angles for brine-CO2-mica system (surface roughness ∼12nm) at different pressures (0.1MPa, 5MPa, 7MPa, 10MPa, 15MPa, 20MPa), temperatures (308K, 323K, and 343K), and salinities (0wt%, 5wt%, 10wt%, 20wt% and 30wt% NaCl). For the same experimental matrix, CO2-brine interfacial tensions have also been measured using the pendant drop technique. The results indicate that both advancing and receding contact angles increase with pressure and salinity, but decrease with temperature. On the contrary, CO2-brine interfacial tension decrease with pressure and increase with temperature. At 20MPa and 308K, the advancing angle is measured to be ∼110°, indicating CO2-wetting. The results have been compared with various published literature data and probable factors responsible for deviations have been highlighted. Finally we demonstrate the implications of measured data by evaluating CO2 storage heights under various operating conditions. We conclude that for a given storage depth, reservoirs with lower pressures and high temperatures can store larger volumes and thus exhibit better sealing efficiency.