Adsorption Properties of Triethylene Glycol on a Hydrated {101̅4} Calcite Surface and Its Effect on Adsorbed Water

Black Sea hydrate production value and options for clean energy production

Natural gas hydrates of Bulgaria and Romania in the Black Sea have been subject to studies by several European research projects. The current understanding of the hydrate distribution, and the total amounts of hydrate in the region, makes it interesting to evaluate in terms of commercial potential. In this study, we have evaluated some well-known hydrate production methods. Thermal stimulation and adding chemicals are considered as not economically feasible. Pressure reduction may not be efficient due to the endothermic dissociation of hydrates and long-term cooling of the sediments. Chemical work due to pressure reduction is an additional mechanism but is too slow to be commercially feasible. Adding CO₂/N₂, however, has a dual value. In the future, CO₂ can be stored at a price proportional to a CO₂ tax. This is deducted from the value of the released natural gas. The maximum addition of N₂ is around 30 mol% of the CO₂/N₂ mixture. A minor addition (in the order of 1 mol%) of CH₄ increases the stability of the hydrate created from the injection gas. The maximum N₂ amount is dictated by the demand for the creation of a new hydrate from injection gas but also the need for sufficient heat release from this hydrate formation to dissociate the in situ CH₄ hydrates. An additional additive is needed to accelerate the formation of hydrate from injection gas while at the same time reducing the creation of blocking hydrate films. Based on reasonable assumptions and approximations as used in a verified kinetic model it is found that CH₄/CO₂ swapping is a feasible method for Black Sea hydrates. It is also argued that the technology is essentially conventional petroleum technology combined with learning from projects on aquifer storage of CO₂, and a thermodynamic approach for design of appropriate injection gas. It is also argued that the CH₄/CO₂ swap can be combined with well-known technology for steam cracking of produced hydrocarbons to H₂ and CO₂ (for re-injection).

Molecular Simulations of Surfactant Adsorption on Iron Oxide from Hydrocarbon Solvents

The performance of organic friction modifiers (OFMs) depends on their ability to adsorb onto surfaces and form protective monolayers. Understanding the relationship between OFM concentration in the base oil and the resulting surface coverage is important for improving lubricant formulations. Here, we use molecular dynamics (MD) simulations to study the adsorption of three OFMs─stearic acid (SA), glycerol monoostearate (GMS), and glycerol monooleate (GMO)─onto a hematite surface from two hydrocarbon solvents─n-hexadecane and poly(α-olefin) (PAO). We calculate the potential of mean force of the adsorption process using the adaptive biasing force algorithm, and the adsorption strength increases in the order SA < GMS < GMO. We estimate the minimum area occupied by OFM molecules on the surface using annealing MD simulations and obtained a similar hard-disk area for GMS and GMO but a lower value for SA. Using the MD results, we determine the adsorption isotherms using the molecular thermodynamic theory (MTT), which agree well with one previous experimental data set for SA on hematite. For two other experimental data sets for SA, lateral interactions between surfactant molecules need to be accounted for within the MTT framework. SA forms monolayers with lower surface coverage than GMO and GMS at low concentrations but also has the highest plateau coverage. We validate the adsorption energies from the MD simulations using high-frequency reciprocating rig friction experiments with different concentrations of the OFMs in PAO. For OFMs with saturated tailgroups (SA and GMS), we obtain good agreement between the simulations and the experiments. The results deviate for OFMs containing Z-unsaturated tailgroups (GMO) due to the additional steric hindrance, which is not accounted for in the current simulation framework. This study demonstrates that MD simulations, alongside MTT, are an accurate and efficient tool to predict adsorption isotherms at solid-liquid interfaces.

Small Alcohols as Surfactants and Hydrate Promotors

Many methods to produce hydrate reservoirs have been proposed in the last three decades. Thermal stimulation and injection of thermodynamic hydrate inhibitors are just two examples of methods which have seen reduced attention due to their high cost. However, different methods for producing hydrates are not evaluated thermodynamically prior to planning expensive experiments or pilot tests. This can be due to lack of a thermodynamic toolbox for the purpose. Another challenge is the lack of focus on the limitations of the hydrate phase transition itself. The interface between hydrate and liquid water is a kinetic bottle neck. Reducing pressure does not address this problem. An injection of CO2 will lead to the formation of a new CO2 hydrate. This hydrate formation is an efficient heat source for dissociating hydrate since heating breaks the hydrogen bonds, directly addressing the problem of nano scale kinetic limitation. Adding limited amounts of N2 increases the permeability of the injection gas. The addition of surfactant increases gas/water interface dynamics and promotes heterogeneous hydrate formation. In this work we demonstrate a residual thermodynamic scheme that allows thermodynamic analysis of different routes for hydrate formation and dissociation. We demonstrate that 20 moles per N2 added to the CO2 is thermodynamically feasible for generating a new hydrate into the pores. When N2 is added, the available hydrate formation enthalpy is reduced as compared to pure CO2, but is still considered sufficient. Up to 3 mole percent ethanol in the free pore water is also thermodynamically feasible. The addition of alcohol will not greatly disturb the ability to form new hydrate from the injection gas. Homogeneous hydrate formation from dissolved CH4 and/or CO2 is limited in amount and not important. However, the hydrate stability limits related to concentration of hydrate former in surrounding water are important. Mineral surfaces can act as hydrate promotors through direct adsorption, or adsorption in water that is structured by mineral surface charges. These aspects will be quantified in a follow-up paper, along with kinetic modelling based on thermodynamic modelling in this work.

Atomistic insight into salinity dependent preferential binding of polar aromatics to calcite/brine interface: implications to low salinity waterflooding

This paper resolve the salinity-dependent interactions of polar components of crude oil at calcite-brine interface in atomic resolution. Molecular dynamics simulations carried out on the present study showed that ordered water monolayers develop immediate to a calcite substrate in contact with a saline solution. Carboxylic compounds, herein represented by benzoic acid (BA), penetrate into those hydration layers and directly linking to the calcite surface. Through a mechanism termed screening effect, development of hydrogen bonding between –COOH functional groups of BA and carbonate groups is inhibited by formation of a positively-charged Na⁺ layer over CaCO₃ surface. Contrary to the common perception, a sodium-depleted solution potentially intensifies surface adsorption of polar hydrocarbons onto carbonate substrates; thus, shifting wetting characteristic to hydrophobic condition. In the context of enhanced oil recovery, an ion-engineered waterflooding would be more effective than injecting a solely diluted saltwater.

Mechanistic Study of Wettability Changes on Calcite by Molecules Containing a Polar Hydroxyl Functional Group and Nonpolar Benzene Rings

Oil extraction efficiency strongly depends on the wettability status (oil- vs water-wet) of reservoir rocks during oil recovery. Aromatic compounds with polar functional groups in crude oil have a significant influence on binding hydrophobic molecules to mineral surfaces. Most of these compounds are in the asphaltene fraction of crude oil. This study focuses on the hydroxyl functional group, an identified functional group in asphaltenes, to understand how the interactions between hydroxyl groups in asphaltenes and mineral surfaces begin. Phenol and 1-naphthol are used as asphaltene surrogates to model the simplest version of asphaltenes. Adsorption of oil molecules on the calcite {101̅4} surface is described using static quantum-mechanical density functional theory (DFT) calculations and classical molecular dynamics (MD) simulations. DFT calculations indicate that adsorption of phenol and 1-naphthol occurs preferentially between their hydroxyl group and calcite step edges. 1-Naphthol adsorbs more strongly than phenol, with different adsorption geometries due to the larger hydrophobic part of 1-naphthol. MD simulations show that phenol can behave as an agent to separate oil from the water phase and to bind the oil phase to the calcite surface in the water/oil mixture. In the presence of phenol, partial separation of water/oil with an incomplete lining of phenol at the water/oil boundary is observed after 0.2 ns. After 1 ns, perfect separation of water/oil with a complete lining of phenol at the water/oil boundary is observed, and the calcite surface becomes oil-wet. Phenol molecules enclose decane molecules at the water-decane boundary preventing water from repelling decane molecules from the calcite surface and facilitate further accumulation of hydrocarbons near the surface, rendering the surface oil-wet. This study indicates phenol and 1-naphthol to be good proxies for polar components in oil, and they can be used in designing further experiments to test pH, salinity, and temperature dependence to improve oil recovery.