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Growing interest in liquefied natural gas (LNG) as a rocket fuel demands reliable prediction and an improved understanding of the changes in its composition arising from the preferential boil-off of lighter components during long duration storage. Unfortunately, current methods of predicting boil-off gas (BOG) evolution from cryogenic liquids are based on limited experimental data. This work reports a series of new experiments which measure the temporal change in BOG production, composition, and pressure at industrially relevant conditions for both ternary mixtures of methane, ethane, and nitrogen and an LNG mixture used as rocket fuel. Faster pressure build-up rates are consistently observed with decreasing initial liquid volume fraction, whilst a decline of 8% in the LNG higher heating value was observed after thirty-three days of weathering. The data is compared with a robust and efficient superheated vapor (SHV) model, implemented in the software package BoilFAST, which allows for reliable calculations of self-pressurisation and boil-off losses for different tank geometries and thermal insulation systems. The model exhibits good agreement with the experimental data across all conditions explored. Finally, the potential effect of LNG composition and heating value changes on rocket engine performance was assessed by examining changes in the adiabatic flame temperature and burnt gas volume ratio. While our data suggest that the rocket engine performance would improve as a result of weathering, the effectiveness of the weathered LNG as a coolant in a regeneratively cooled rocket engine decreases.

Hydrogen is emerging as one of the most promising energy carriers for a decarbonised global energy system. Transportation and storage of hydrogen are critical to its large-scale adoption and to these ends liquid hydrogen is being widely considered. The liquefaction and storage processes must, however, be both safe and efficient for liquid hydrogen to be viable as an energy carrier. Identifying the most promising liquefaction processes and associated transport and storage technologies is therefore crucial; these need to be considered in terms of a range of interconnected parameters ranging from energy consumption and appropriate materials usage to considerations of unique liquid-hydrogen physics (in the form of ortho–para hydrogen conversion) and boil-off gas handling. This study presents the current state of liquid hydrogen technology across the entire value chain whilst detailing both the relevant underpinning science (e.g. the quantum behaviour of hydrogen at cryogenic temperatures) and current liquefaction process routes including relevant unit operation design and efficiency. Cognisant of the challenges associated with a projected hydrogen liquefaction plant capacity scale-up from the current 32 tonnes per day to greater than 100 tonnes per day to meet projected hydrogen demand, this study also reflects on the next-generation of liquid-hydrogen technologies and the scientific research and development priorities needed to enable them.

The production of methane (CH4) from natural-gas hydrate deposits via molecular replacement by injected, thermodynamically more favourable, carbon dioxide (CO2) is a promising method of energy prod...

Solid-fluid interactions underpin the efficacy of functional porous materials across a diverse array of chemical reaction and separation processes. However, detailed characterization of interfacial phenomena within such systems is hampered by their optically opaque nature. Motivated by the need to bridge this capability gap, we report low-magnetic-field two-dimensional (2D) 1H nuclear spin relaxation measurements as a noninvasive probe of adsorbate identity and interfacial dynamics, exploring the relaxation characteristics exhibited by liquid hydrocarbon adsorbates confined to a model mesoporous silica. For the first time, we demonstrate the capacity of this approach in distinguishing functional group-specific relaxation phenomena across a diverse range of alcohols and carboxylic acids employed as solvents, reagents, and liquid hydrogen carriers, with distinct relaxation responses assigned to the alkyl and hydroxyl moieties of each confined liquid. Uniquely, this relaxation behavior is shown to correlate with adsorbate acidity, with the observed relationship rationalized on the basis of surface-adsorbate proton-exchange dynamics. Our results demonstrate that nuclear spin relaxation provides a molecular-level perspective on sorbent/sorbate interactions, motivating the exploration of such measurements as a unique probe of adsorbate identity within optically opaque porous media.

Understanding solid-fluid interactions within porous materials is critical for their efficient utilisation across chemical reaction and separation processes. However, detailed characterisation of interfacial phenomena within such systems is hampered by their optically opaque nature. Motivated by the need to bridge this capability gap, we detail here the application of low magnetic field 2D 1H nuclear spin relaxation measurements as a non-invasive probe of sorbate/sorbent interactions, exploring the relaxation characteristics exhibited by liquid adsorbates confined to a model mesoporous silica. For the first time, we demonstrate the capacity of such measurements to distinguish functional group-specific relaxation phenomena across a diverse range of protic adsorbates of wide importance as solvents, reagents, and hydrogen carriers, with distinct relaxation environments assigned to the alkyl and hydroxyl moieties of the confined liquids. Uniquely, this relaxation behaviour is shown to correlate with adsorbate acidity, with the observed relationship rationalised on the basis of surface-adsorbate proton exchange dynamics.

Tortuosity is an important physical characteristic of porous materials; for example, it is a critical parameter determining the effective diffusion coefficient dictating mixing between miscible fluids in porous rock structures as is relevant to enhanced gas recovery processes. Accurate measurement of tortuosity remains challenging, resulting in various definitions dictated largely by the measurement protocol applied. Here, we focus primarily on ‘diffusive’ tortuosity (τd), which is defined as the ratio of the bulk fluid diffusion coefficient to the restricted diffusion coefficient applicable to the porous media under study. Specifically, we consider carbonate rock cores ranging in permeability from 2 to 5300 mD and adapt pulsed field gradient (PFG) NMR methodology such that accurate measurements of tortuosity are obtained over a sufficiently representative length scale of the porous media. To this end, we deploy supercritical methane as a probe molecule exploiting both its high mobility and proton density. Tortuosity measurements are shown to be independent of both pressure and diffusion observation time, conclusively proving that our measurements are in the asymptotic regime in which all of the pore space is adequately sampled by the diffusing methane molecules. The resultant ‘diffusive’ tortuosity measurements (which ranged from 3.1 to 5.6) are then compared against independent electrical conductivity measurements of tortuosity using a two-electrode impedance technique applied to the carbonate samples saturated with brine solution. Agreement between the ‘diffusive tortuosity,’ as measured by PFG NMR, and ‘electrical’ tortuosity was remarkably good (within 10%), given the very different measurements techniques used, for most of the carbonate rock samples considered.

Asphaltenes are widely associated with the unwanted stability of water-in-crude oil (w/o) emulsions due to their inhibitory effect on water droplet coalescence. Here, we seek to prove that certain crude oil resins that can bind with asphaltenes, hereafter referred to as binding resins, are capable of solvating these asphaltenes such that the w/o emulsion destabilizes. W/o emulsions were formed using a variety of crude oils as well as model oils with varying amounts of resins and asphaltenes. A modified SARA fractionation technique was adopted to extract the required resins and asphaltenes. Emulsion stability was tracked over time both visually and via the use of pulsed field gradient nuclear magnetic resonance to quantify the emulsions’ water droplet size distributions. It was conclusively found that the binding resins significantly improved the demulsification rate of the emulsions formed using both crude oil and model oils. In the case of the model oils, this influence could only be attributed to the re...

The production of water during crude oil extraction may result in the formation of stable water-in-oil emulsions. Such emulsions are problematic for a variety of reasons; for example, they increase the fluid viscosity and hence the pumping costs. Previously, Ling; [NMR Studies of the Effect of CO2 on Oilfield Emulsion Stability. Energy Fuels 2016, 307, 5555–5562] have shown that treating these water-in-crude oil emulsions with subcritical CO2 at 50 bar can lead to their breakage. These measurements utilized benchtop NMR pulsed field gradient (PFG) techniques to monitor the evolution in the emulsion droplet size distribution, which is a precursor to emulsion breakage. Experimental limitations meant, however, that the measurements were performed only following depressurization of the applied CO2 and as such were unable to directly distinguish between two potential mechanisms for emulsion breakage as proposed in the literature: (i) CO2 bubble formation within the water droplets upon depressurization or (ii) ...

Injection of carbon dioxide (CO2) into a natural gas reservoir is an emerging technology for enhanced natural gas recovery (EGR) realizing increased natural gas production whilst sequestering the injected CO2. However, given that CO2 and natural gas are completely miscible, simulation of potential EGR scenarios is required to determine when breakthrough of CO2 will occur at the natural gas production wells. For such reservoir simulations to be reliable (independent of software used), accurate dispersion data between CO2 and natural gas at relevant reservoir conditions are required. To this end, we apply one-dimensional magnetic resonance imaging (MRI) to quantify this dispersion process in situ in both sandstone and carbonate rock cores. Specifically we apply the SPRITE MRI sequence (Balcom et al. in J Magn Reson Ser A 123(1):131–134, 1996. https://doi.org/10.1006/jmra.1996.0225 ) to facilitate quantitative axial profiles of methane (CH4) content during core flooding processes between CO2 and CH4. Simultaneously we measure, using infrared, the effluent CO2 and CH4 concentrations enabling ex situ dispersion measurements. Via comparison with the corresponding MRI data, the erroneous contributions to dispersion from entry/exit effects and mixing in piping to and from the rock core holder are quantified. Furthermore, we demonstrate how nuclear magnetic resonance T2 measurements can be uniquely used to probe the pore size occupancy of the CH4 during the core flooding process.

The emergence and accumulation of microplastics (MPs) in various aquatic environments have recently raised significant concerns. Wastewater treatment plants (WWTPs) have been identified as one of the major sources of MPs discharge to the environment, implying a substantial need to improve advanced techniques for more efficient removal of MPs. Polymeric membranes have been proven effective in MPs removal. However, fouling is the main drawback of membrane processes and MPs can foul the membranes due to their small size and specific surface properties. Hence, it is important to investigate the impacts of MPs on membrane fouling to develop efficient membrane-based techniques for MPs removal. Although membrane technologies have a high potential for MPs removal, the interaction of MPs with membranes and their fouling effects have not been critically reviewed. The purpose of this paper is to provide a state-of-the-art review of MPs interaction with membranes and facilitate a better understanding of the relevant limitations and prospects of the membrane technologies. The first section of this paper is dedicated to a review of recent studies on MPs occurrence in WWTPs aiming to determine the most frequent MPs. This is followed by a summary of recent studies on MPs removal using membranes and discussions on the impact of MPs on membrane fouling and other probable issues (abrasion, concentration polarisation, biofouling, etc.). Finally, some recommendations for further research in this area are highlighted. This study serves as a valuable reference for future research on the development of anti-fouling membranes considering these new emerging contaminates.

Complex organic molecules are of great importance to research and industrial chemistry and typically synthesized from smaller building blocks by multistep reactions. The ability to perform multiple (distinct) transformations in a single reactor would greatly reduce the number of manipulations required for chemical manufacturing, and hence the development of multifunctional catalysts for such one-pot reactions is highly desirable. Here we report the synthesis of a hierarchically porous framework, in which the macropores are selectively functionalized with a sulfated zirconia solid acid coating, while the mesopores are selectively functionalized with MgO solid base nanoparticles. Active site compartmentalization and substrate channelling protects base-catalysed triacylglyceride transesterification from poisoning by free fatty acid impurities (even at 50 mol%), and promotes the efficient two-step cascade deacetalization-Knoevenagel condensation of dimethyl acetals to cyanoates.

Understanding the uptake and storage of gases by microporous materials is important for our future energy security. As such, we demonstrate here the application of two-dimensional NMR relaxation experiments for probing the admission and corresponding exchange dynamics of methane within microporous zeolites. Specifically, we report low-field (12.7 MHz) 1H NMR relaxation-exchange correlation measurements of methane within commercial LTA zeolites (3A and 4A) at 25 and 35 bar and ambient temperature. Our results demonstrate the clear identification of bulk–pore and pore–pore exchange processes within zeolite 4A, facilitating the calculation and comparison of effective exchange rate dynamics across varying diffusion length scales and gas pressures. Additional data acquired for zeolite 3A reveals the sensitivity of NMR relaxation phenomena to size-exclusive gas admission phenomena, illustrating the potential of benchtop NMR protocols for material screening applications.

The application of bacterial cellulose (BC) as a wrapping material for vacuum-packaged beef was studied and compared against unwrapped beef for up to 3 weeks. The impact of BC wrap on the weight loss, purge accumulation, and drip loss were assessed along with low-field nuclear magnetic resonance, physicochemical, microbiological, and sensorial evaluations. The BC wrap significantly (P < 0.05) reduced purge accumulation in vacuum packages which was confirmed by an increased swelling ratio and scanning electron microscopy images. Colorimetric measurements showed significantly (P < 0.05) increased redness and yellowness values in wrapped samples compared to unwrapped samples. BC wrap did not affect pH, tenderness, and odor of meat, but significantly (P < 0.05) increased lipid oxidation, and numbers of lactic acid bacteria and Brochothrix thermosphacta counts. This study shows that BC wrap has potential as a purge absorbent in vacuum packaged meat. Practical Application: Bacteria cellulose has good water holding capacity that can be utilized to absorb purge exudate from beef. It helps to improve the appearance and consequently consumer acceptance of vacuum packed beef.

Rigorous quantification of hydrate formation probability in the presence of mono-ethylene glycol (MEG) is crucial for understanding hydrate formation risk in oil and gas production systems where the delivery of MEG for complete thermodynamic inhibition is either economically or practically infeasible. Using thermoelectrically cooled, stirred reactors, we have obtained 3,056 hydrate nucleation points in total. With these data we quantify the probability of hydrate formation in under-dosed MEG systems as a function of subcooling from the hydrate phase boundary, at MEG dosages between (5 and 25) wt% with respect to the aqueous phase. Although the addition of the MEG led to reductions in the measured formation temperatures, the corresponding subcooling distributions were similar to those measured in MEG-free systems. Furthermore, isothermal measurements at a fixed subcooling of (3.6 ± 0.1) K across a range of MEG loadings yielded comparable exponential induction time distributions. These results establish that MEG does not significantly affect either the nucleation rate or distribution of hydrate formation probabilities. Initial subcooling-dependent hydrate growth rates were also measured and reduced proportionally with the MEG dosage. Finally, we show how a low dosage kinetic hydrate inhibitor can be used together with MEG to further inhibit hydrate formation, by reducing both nucleation and growth rate. The results detailed here may be useful to the successful implementation of economically-viable, risk-based hydrate management strategies in under-inhibited systems.

Nuclear magnetic resonance (NMR) well logging is a well-established technique for in-situ fluid measurement. It is however not routinely used in the mining industry to quantify water content in high magnetic susceptibility iron ore rock cuttings because the ore’s magnetic properties adversely affect the measurement. In this study the relationship between NMR signal intensity and magnetic susceptibility is studied using a low magnetic field (2 MHz) benchtop NMR instrument. Magnetic susceptibility is commonly measured during well logging protocols and therefore could be used to correct and hence render quantitative NMR measurements of moisture content in iron ore. In this study NMR signal from water-saturated synthetic samples (magnetite/maghemite/hematite mixed with borosilicate glass beads) is measured as a function of iron content and magnetic susceptibility to obtain such a correlation. This correlation is then applied to iron ore rock cuttings. Comparison with gravimetric measurements show that a standard error of estimate of water content across all samples tested of 6.4 wt% using no correction, is reduced to 1.5 wt% using the corrections, corresponding to a relative error reduction from 47% to 11%. Additional comparison with whole rock cores shows that a higher magnetic susceptibility threshold for using the corrections is required for whole rock cores than for the rock cuttings, this difference requires further study. These results encourage the broad use of these types of correlations for NMR measurements of iron rich cuttings and application of NMR well logging to iron ore deposits.

We present a model for hydrate deposition and sloughing in gas dominated pipelines which allows for rapid estimations of the pressure and temperature profiles along a horizontal pipeline during normal operation in the hydrate forming region in the presence of monoethylene glycol (MEG). Previous models assume that the hydrate deposit growing at the pipe wall is stable, which may lead to an overestimation of the pressure drop over time. Hydrate growth rates were calculated using a classical hydrate kinetic model combined with a simplified two-phase flow model for pipelines in the annular flow regime with droplet entrainment. Hydrate growth at the pipe wall, deposition of hydrate particles from the gas stream and sloughing due to shear fracture of the deposited film contributed to the evolution of the hydrate deposit. The model parameters included a scaling factor to the kinetic rate of hydrate growth and a particle deposition efficiency factor. The fraction of deposited particles forming a stable hydrate film at the pipe wall through sintering and the shear strength of the deposit were introduced as two additional parameters to enable simulation of sloughing events. The tuned model predicted hydrate formation within 40% and pressure drop within 50% of measurements previously obtained in a gas-dominated flow loop over a wide range of subcoolings, MEG concentrations and high and intermediate gas velocities. The observed decrease of the kinetic factor with decreasing gas velocity indicated larger resistances to hydrate growth in the entrained droplets at lower flow rates, while the increase of the deposition parameter with MEG concentration was consistent with a particle adhesion/cohesion mechanism based on the formation of a capillary bridge. The preliminary sloughing model presented in this work, combined with flowloop testing, has allowed the first in-situ determinations of the effective shear strength of the hydrate deposits (in the range of 100–200 Pa) which is a key property to predict hydrate detachment and accumulation in gas-dominated pipelines.

An NMR Q-switch was designed and constructed specifically for use with low-field NMR apparatus. This featured a comparatively simple resistive damping design. It served to reduce the r.f. probe ring-down time, and hence reduced the signal acquisition delay from 25 ms to 9 ms, on an Earth’s magnetic field NMR system. The advantage of this earlier acquisition was demonstrated for both an aqueous suspension of iron oxide particles and using an NMR flow meter.

Recovering methane (CH4) via the injection of carbon dioxide (CO2) into a CH4-hydrate-bearing reservoir is a highly attractive mechanism for meeting the world's future energy demand, since it offers the prospect of carbon-neutral energy production. Although the process of CH4–CO2 exchange in hydrate has been demonstrated in numerous laboratory experiments, deployment is hampered by an incomplete understanding of the underlying mechanism of exchange, inconsistencies in reported performance, and insufficient rates of recovery. In this study, the combined effect of thermal stimulation and hydrate-sediment ratio on the rate and degree of CH4 recovery has been quantitatively investigated through a series of large-volume, high-pressure core-flooding experiments on well-characterized synthetic hydrate-sediments using in situ Raman spectroscopy of the effluent vapour. The effect of controlled thermal stimulation has been related to a shell–core model of hydrate exchange, showing that repeated thermal stimulation is effective in temporarily increasing the exchange rate. Furthermore, a numerical analysis of the effective exchange layer thickness for a general particle size distribution is presented: from the results of this work and studies in the literature, we have established a preliminary heuristic for estimating the extent of exchange at constant temperature and pressure. During an initial phase, the effective exchange layer thickness grows at about 9 μm day−1 to a limiting value around 5 μm, where after further exchange occurs at a rate of less than 0.5 μm day−1. The presence of sediment in combination with thermal stimulation was found to significantly increase the rate and overall recovery of CH4, from 28% for a pure hydrate core to 82% for a hydrate-sediment core. This increased recovery is attributed to wetting of the unconsolidated-sediment during exchange. In the context of designing CH4 production from hydrate, these results establish that staged thermal stimulation is an effective means of enhancing CH4 recovery through CO2 exchange and can be improved by applying a series of smaller temperature increments. The enhanced recovery observed in the presence of sediment has important implications for optimized CO2 injection and sequestration, due to the preferential formation of pore-filling hydrate and the associated impact on permeability.

Enhanced natural gas recovery (EGR) with supercritical (sc)CO2 sequestration offers the prospect of increased natural gas recovery. High-fidelity reservoir simulations offer a method to quantify the risk of contamination of produced gas by the injected scCO2. Simulations of scCO2 mixing with the reservoir gas have been reported; however the effects of connate water on EGR have not been effectively explored. We extend a prior EGR simulation tool (Patel, May and Johns, 2016; Ref. [1]) to incorporate connate water accounting for its effect on dispersivity and permeability; chemical equilibrium is modelled using a novel, computationally efficient Lagrange multiplier-based approach. The code is applied to a ‘quarter five-spot’ benchmark scenario. The inclusion of connate water generally resulted in a reduction in breakthrough time and a decrease in methane recovery. The connate water's largest effect was to change the scCO2 flow field, which sank towards the reservoir floor, flooded the lowermost accessible layers and entered the production well via a high throughput channel (‘coning’). The magnitude of these effects were, however, sensitive to well perforation depth, the influence of which was subsequently studied systematically. Well perforation depth was found to determine the duration of these sinking and coning events in a non-linear manner.

Gas hydrates are ice-like solids that may form in crude oil flowlines under high pressure and at low temperature, resulting in the formation of viscous hydrate-laden oil slurries. The magnitude of the slurry viscosity has been suggested as a primary means of determining the risk and severity of flow blockage, but there is a dearth of data available to calibrate predictive models of hydrate-in-oil slurry viscosity. This work deploys a controlled-stress, high-pressure rheometer to characterize the rheological properties of methane hydrate-in-crude oil slurries, which were generated in situ from water-in-oil emulsions. A vane blade rotor was found to maintain sufficient methane saturation in the oil phase during the hydrate growth period to allow near full conversion of the water. Dynamic measurements with the rheometer were able to separate the contributions to the viscosity change as the emulsion converted to a hydrate slurry due to (i) formation of the solid particles and (ii) reduction of the methane content in the oil continuous phase. For 5–30 vol% watercut systems, the slurry viscosity increased between 20 and 60 times during hydrate growth, whereas, under equivalent conditions for a 20% watercut emulsion, the viscosity increase due to the desaturation of methane from the oil phase was less than a factor of two. The steady-state hydrate-in-oil slurry demonstrated shear thinning behavior at both 1 and 5° C. The measured slurry relative viscosity deviated between 12 and 212% from the current industry-standard hydrate-in-oil slurry viscosity model, indicating the need for model improvement. After an eight-hour annealing period to simulate subsea shut-in, the yield stress of the hydrate-in-oil slurries varied between 3 and 25 Pa over 5 to 25 vol% hydrate.

Surface tension predictions of hydrocarbon mixtures at vapour-liquid equilibrium are crucially important and used in the design of many unit operations in the production of liquefied natural gas (LNG). Predictive models for surface tension are not well tested for hydrocarbon mixtures at high pressures due to the limited data available at relevant conditions. A differential capillary rise apparatus consisting of a high-pressure sapphire equilibrium cell was constructed and used to measure the surface tension of methane + propane mixtures along three isotherms T = (272.23, 285.51 and 303.34) K at pressures up to 9 MPa. The capillary diameters were calibrated using pure saturated propane at 271 K, and the technique was validated by measurements of pure ethane. The measured surface tensions were compared with the available data and the predictions of various models, including the Parachor method and Linear Gradient Theory: both were able to describe the data within their uncertainty. However, the default surface tension model for hydrocarbon mixtures implemented in the widely-used software package REFPROP 9.1 gave poor predictions; this was rectified through the implementation of the Parachor method in a beta-version of REFPROP 9.2. Critical points were also measured from observations of critical opalescence and the disappearance of the bulk interface. The measured mixture critical points were consistent with, and extended, literature values for this binary system. The measured critical points differed by between 0.5 and +27 K from predictions made with the GERG-2008 equation of state (EOS) and between −5 and +10 K for the Peng-Robinson EOS.

Enhanced Gas Recovery (EGR) involves CO2 injection into natural gas reservoirs to both increase gas recovery and trap CO2. EGR viability can be determined by reservoir simulations; however these require a description of fluid dispersion (mixing) between the supercritical CO2 and natural gas. Here we quantify this dispersivity (α) in sandstone rock plugs as a function of residual water fraction. To ensure the accuracy of such data, we designed a novel core flooding experimental protocol that ensured an even spatial distribution of water, minimised erroneous entry/exit contributions to mixing, and minimised dissolution of the CO2 into the water phase. Dispersivity was found to increase significantly with water content, although the differences in α between sandstones were eliminated upon the inclusion of residual water. This enabled development of a correlation between α and water content and, hence, between the dispersion coefficient and Peclet number that is readily incorporable into reservoir simulations. This article is protected by copyright. All rights reserved.

The high operating pressures and distances of deep water tiebacks increase the likelihood of hydrate blockage during transient operations such as shut-in and restart. In many cases, complete hydrate avoidance through chemical management may become cost prohibitive, particularly later in the field’s life. However, a subclass of crude oils has been observed in which hydrate blockages do not form during restart, rendering active hydrate prevention unnecessary. Over the past 20 years, limited information has been reported about the chemical or physical mechanisms that enable this plug-resistive behavior. This study presents an extensive and systematic method of characterizing whether an oil may naturally resist hydrate plug formation, including (i) chemical and physical property analysis, (ii) water-in-oil emulsion behavior, and (iii) the effect of the oil on hydrate blockage formation mechanics. This last set of experiments utilizes both a high-pressure rheometer and a sapphire autoclave to allow direct obse...

A high-pressure stirred autoclave cell equipped with a focused beam reflectance measurement (FBRM) probe and a particle video microscope (PVM) was used to study hydrate formation and plugging in gas–water systems as a function of shear rate. These probes allowed estimates of the mean hydrate particle size and number of hydrate particles to be correlated with the hydrate volume fraction and the hydrate slurry’s resistance-to-flow. Before reaching the hydrate volume fraction φtransition at which the hydrate slurry first exhibits a measurable increase in resistance-to-flow at ≈(16 ± 2) vol %, clear changes in the measured number and size of the hydrate particles were observed. Initially, hydrate particles within the FBRM probe’s field of view decreased in size and increased in number until a maximum was reached at concentrations of 2–9 vol % (increasing with shear rate). However, with continued hydrate growth, the number of particles within the FBRM probe’s field of view unexpectedly decreased and eventually...

By-line Nuclear Magnetic Resonance (NMR) measurements of emulsion droplet size distributions are presented based on pulsed field gradient (PFG) measurements. These are performed on temporarily immobilised samples extracted from a main process stream with corrections applied for any temporal variations in sample composition. The overall methodology is initially applied to pure fluids and then a range of water-in-oil emulsions. It is then demonstrated on an emulsification flow loop in which three commercial demulsifiers are separately applied; significant variation in their performance with respect to increasing emulsion droplet size (and thus emulsion destabilisation) is observed. Finally, a more rapid PFG method, Difftrain, is successfully demonstrated with the measured mean emulsion droplet size being used as the input into standard PID control of applied shear and hence the extent of emulsification.

Complex organic molecules are of great importance to academic and industrial chemistry and typically synthesised from smaller building blocks by multistep reactions. The ability to perform multiple (distinct) transformations in a single reactor would greatly reduce the number of manipulations required for chemical manufacturing, and hence the development of multifunctional catalysts for such one-pot reactions is highly desirable. Here we report the synthesis of a novel hierarchically porous framework, in which the macropores are selectively functionalised with a SO4/ZrO2 solid acid coating, while the mesopores are selectively functionalised with MgO solid base nanoparticles. The spatially orthogonal distribution of acid and base catalytic sites permits the efficient two-step cascade deacetylation and Knoevenagel condensation of dimethyl acetals to cyanoates, and the simultaneous esterification and transesterification of a high free fatty acid content triglyceride.

Current methods of estimating boil-off gas (BOG) rates for large-scale liquefied natural gas (LNG) storage tanks are largely empirical and based on limited available experimental data. More accurate models would be extremely valuable for estimating the potential for excessive BOG generation during LNG storage and transportation scenarios as well as providing critical inputs into the design of BOG re-liquefaction systems. This study reports a series of experiments that have been conducted for LNG-like binary mixtures of methane and ethane to measure the BOG production and resultant pressure change under various industrially relevant conditions. Experimental data and observations made in this work are compared with both the available literature and with the predictions of a new non-equilibrium model that uses the GERG-2008 equation of state to calculate relevant LNG and BOG properties. The data reveal three distinct stages of BOG evolution, here labelled as self-pressurisation, transient, and homogenous. It is observed that, in the self-pressurisation stage, the thickness of a thermally stratified layer adjacent to the liquid–vapor interface increases with time. The transient stage is defined to commence when the system reaches the specified relief pressure and the homogeneous stage is reached upon the effective elimination of thermal stratification in the LNG. Good agreement exists between this new model and the experimental and literature data acquired during the self-pressurisation and homogeneous stages. In the transient stage, the model does not accurately quantify the BOG rate indicating a need to incorporate the effects liquid thermal stratification in future model development.

The formation of gas hydrates is crucial to many technological applications including energy production, energy storage, desalination, and CO2 capture. Kinetic hydrate inhibitor (KHI) chemicals have been used industrially for over 25 years to suppress hydrate formation in key industrial applications. However the mechanisms by which they operate, and specifically whether they delay nucleation or just retard growth, remain open questions. Here induction time probability distributions for methane hydrates were measured at several constant subcoolings as a function of KHI concentration. This allowed the hydrate nucleation and growth rates at each condition to be separately quantified through the observed induction times and initial gas consumption rates, respectively. Adding a KHI produces a Gamma-distribution of induction times, characterized by two parameters: nucleation rate and the average number of events associated with detection. This is qualitatively different to the exponential distributions of induction time probabilities observed in systems without any KHI. These data reveal how KHIs both increase the nucleation work required to form a critical nuclei and increase the effective number of sites where nucleation could occur. By showing unambiguously how KHIs delay hydrate nucleation at low subcoolings, this work opens systematic pathways for developing improved chemicals for either hydrate inhibition or promotion. The approach to inhibitor testing demonstrated here may also help natural gas producers assess the costs and benefits of competing designs for hydrate management.

A stirred, high-pressure, visual microscopy-based apparatus was used to investigate solid-formation kinetics in LNG-relevant binary mixtures. The apparatus can detect solid crystals as small as 20 µm in a 3.5 mm field of view and is capable of measurements at temperatures as low as 90 K and pressures up to 20 MPa. The apparatus is described in detail and is presented alongside experimental results for two benzene + methane mixtures. Measurements of the solid–fluid equilibrium temperatures for the benzene + methane mixtures at 10 MPa were determined by raising the temperature of the mixture in (0.5 to 1) K steps and observing whether the crystals were still present after 2 h. The equilibrium temperatures were consistent with those predicted using the software package ThermoFAST within the combined experimental and model uncertainties. Formation measurements were carried out using a 100 ppm benzene-in-methane sample. Isobaric constant-cooling experiments at pressures of 8 and 10 MPa were used to construct subcooling formation-probability distributions for this mixture by identifying the temperature at which solid crystals were first observed to form on a copper substrate. The subcooling values at formation ranged from (4.4 to 11.0) K and were used to generate a cumulative probability of formation. The measured formation-probability distribution was fit to a model based on Classical Nucleation Theory to yield an estimate of 5 mJ/m2 for the effective surface free energy of solid benzene in liquid methane on the copper substrate. These results pave the way to probabilistic estimates of risk for solids formation in cryogenic heat exchangers.

Hydrocarbon production from unconventional shale reservoirs has gained increasing worldwide focus, spurred largely by improvements in production techniques. Nuclear magnetic resonance (NMR) is increasingly being explored as a means of characterizing such shale rock. Compared to conventional sandstone and carbonate rocks, shales present a much lower porosity and permeability with NMR signal arising from both producible hydrocarbon fluid content as well as semi-solid organic solids and bitumen. Interpretation of the resultant NMR signal from shales is consequently comparatively more complex. To this end we apply combined NMR free induction decay (FID) and Carr-Purcell-Meilboom-Gill (CPMG) measurements and interpret the spliced data using a combined Gaussian and exponential inversion method. This was applied to a range of shale samples with variable moisture content in an attempt to assess the accuracy of such an approach to delineate the inherent predominantly bitumen signal from that of the added water. The analysis was performed at a range of frequencies (20, 40 and 60 MHz), which are applicable to more widely accessible bench-top NMR spectrometers. Consistently, the Gaussian component of the resultant T2*|T2 distribution was found to be independent of moisture content, scaling rather with the total organic content of the respective shale cores. In contrast, the exponential component of the resultant T2*|T2 distribution was found to scale linearly with the moisture content of the cores.

EGR (Enhanced natural gas recovery) with CO2 sequestration offers the prospect of significant environmental and economic benefits by increasing gas recovery while simultaneously sequestering the greenhouse gas. Field-scale deployment is currently limited as the risks of contamination of the produced gas by injected CO2 are poorly understood. Reservoir simulations offer a method to quantify the risk but only if sufficiently accurate. For the first time, finite element simulations are presented for several EGR scenarios that incorporate the most accurate models available for fluid mixture and rock properties. Specifically, the GERG-2008 EOS (equation of state) is utilised to describe the supercritical fluid mixture's density, as are reference correlations linked to the most accurate experimental data available for diffusivity and viscosity. Realistic values for rock dispersivity and tortuosity determined from high-accuracy core-flooding and NMR (nuclear magnetic resonance) experiments were also integrated. The relative impacts of these properties were investigated for a benchmark layered reservoir with a quarter 5-spot well pattern. Recovery efficiency at different CO2 injection rates was also investigated and was determined to be the dominant consideration: a 100-fold rate increase improved recovery from 53% to 69% while CO2 breakthrough time decreased by less than expected. Collectively, these results emphasise the importance of accurate reservoir simulations for EGR.

Gas hydrate formation is a critical flow assurance risk in oil and gas production, as remediation of blockages may require weeks of operating downtime and represent a significant safety hazard. While many studies over the past two decades have focused on quantifying hydrate blockage risk in crude oil systems, there is a dearth of information available with which to assess hydrate growth rate or blockage severity in natural gas systems, which typically operate between stratified and annular flow regimes. In this investigation, a single-pass gas-dominant flowloop was used to measure hydrate growth and particle deposition rates with variable liquid holdup (1–10 vol%) and subcooling (1–20 °C). A particular focus of this study was the impact of reducing the gas phase velocity to achieve lower liquid entrainment and, therefore, decrease hydrate formation rate. Reducing the gas velocity from 8.7 to 4.6 m/s at a constant subcooling around 6 °C reduced the total formation rate by a factor of six. At these conditions, the sensitivity of hydrate formation rate to velocity was about 40 times greater than the sensitivity to subcooling. This reduction in gas velocity also halved the estimated rate of hydrate deposition on the pipeline wall. Finally, new observations of hydrate wash-out are reported, whereby significant localized hydrate deposits were effectively removed by modulating the subcooling of the flowloop wall from 6 °C to 3.5 °C. The results provide new insight to inform the next generation of predictive hydrate growth and deposition models for gas-dominant flowlines.

Gas hydrates are crystalline solids comprised of a three-dimensional network of water cages that can trap small hydrocarbon molecules at high pressure and low temperature. Formation of gas hydrates can lead to blockages in subsea oil and gas flowlines, where these conditions are readily achieved. As gas reserves mature over time, new CO2-rich reservoirs can be prolific hydrocarbon producers for markets willing to bear the additional production costs. However, there is a lack of understanding about the formation behavior and growth morphology of CO2-rich hydrates. In this work, hydrate growth rate and resistance-to-flow (torque) data for a ternary CO2-rich gas mixture were measured in a high-pressure sapphire autoclave apparatus and were compared with baseline data for a pure methane system. Images of hydrate growth and eventual plug formation were captured for methane hydrate and ternary gas systems, where early hydrate growth in the latter was dominated by an opaque film nucleating at the gas-water-wall interface and growing into both gas and water phases with time. Only 7 vol% methane hydrate was required to increase the motor torque above its baseline value, while at least 20 vol% hydrate was required when formed from the CO2-rich ternary gas. These new observations provide insight into the effect of guest species solubility on hydrate growth and resistance-to-flow in the resultant slurries, which are key parameters when assessing the risk of hydrate blockage in oil and gas pipelines.

Assessment of the viability of enhanced gas recovery (EGR), in which CO2 is injected into natural gas reservoirs, requires accurate and appropriate reservoir simulations. These necessitate provision of parameters describing dispersion between the fluids. Here we systematically measure fluid dispersion in various rock cores (sandstones and carbonates), both dry and at irreducible water saturation, at reservoir conditions. In this manner we evaluate the impact of the irreducible water on the miscible displacement processes. As such this represents the first measurement of dispersion as a function of water saturation for supercritical gases in consolidated media. Complementary measurements of water spatial distribution along the rock axis, as well as the pore size distribution occupied by the water were performed using magnetic resonance techniques. Irreducible water was found to increase dispersivity by a factor of up to 7.3. The dispersion coefficient (K) was measured as a function of velocity and the data for both dry and water-containing samples were successfully combined on a K–Peclet number (Pe) plot, enabling ready future inclusion into EGR reservoir models. The power-law dependence of K upon Pe produced an exponent of 1.2 for dry and water-saturated sandstones and 1.4 for dry and water-saturated carbonates, consistent with literature results (Bijeljic et al., 2011; Honari et al., 2015).

Formation of water-in-crude oil emulsions is a pervasive problem for crude oil production and transportation. Here we investigate the effectiveness of a comparatively low pressure CO2 treatment in terms of breaking these water-in-crude oil emulsions. To this end, we used unique benchtop nuclear magnetic resonance (NMR) technology to measure the droplet size distribution (DSD) of the emulsions. Treatment with 50 bar CO2 for 2 h resulted in significant emulsion destabilization; this was replicated when CO2 was replaced by N2O, which has a solubility in both the aqueous and oil phases similar to that of CO2. Low solubility gases, N2 and CH4, by contrast had no effect on emulsion stability. Treatment with CO2 was also found to have no effect on a model water-in-paraffin oil emulsion stabilized by a synthetic surfactant (Span 80). Collectively, this supported the hypothesis that emulsion destabilization results from CO2 precipitation of asphaltenes as opposed to emulsion droplet film disruption during depressu...

The formation of gas hydrate plugs in deep water oil and gas flowlines poses severe operational and safety hazards. Previous work has established a mechanism able to describe plug formation in oil-continuous systems, which relies on the assumption that all the water remains emulsified in the oil phase. However, light hydrocarbon fluids, including condensates, may not stabilize water-in-oil emulsions, and the current mechanistic model cannot reliably assess the risk of plug formation in this scenario. This study presents a comprehensive set of experiments conducted in a high-pressure sapphire autoclave apparatus using 10 to 70 vol% water in partially-dispersing mineral oil at three fixed rotational speeds: 300, 500 and 900 RPM. Pressure and temperature were monitored continuously in the autoclave, providing direct estimates of hydrate growth rate, alongside measurements of the motor torque required to maintain constant mixing speed. A new conceptual mechanism for plug formation has been developed based on the visual observations made during these experiments, where a small hydrate fraction (2–6 vol%) in the oil phase was observed to disrupt the stratified water–oil interface and help disperse the water into the oil. This disruption was followed by an increase in the hydrate growth rate and particle agglomeration in the oil phase. In the final stages of hydrate growth for systems with low turbulence and high watercut, hydrate particles in the visual autoclave were observed to form a moving bed followed by full dispersion of water and oil, rapid hydrate growth and deposition on the wall. These rapid hydrate growth and deposition mechanisms significantly increased the maximum resistance-to-flow for partially-dispersing systems in comparison with mixtures that are fully dispersed under similar conditions.

Hypothesis Shear-induced droplet diffusion of flowing hard spheres is relatively well understood and has been extensively studied both experimentally and via simulations. The same however is not true of soft spheres, specifically emulsions, despite their broad and extensive industrial relevance. Here we seek to demonstrate that appropriate NMR techniques can be used to quantitatively measure shear-induced droplet diffusion. Limited literature indicates that dilute dispersions of soft spheres experience significantly larger shear-induced droplet diffusion relative to otherwise equivalent hard sphere suspensions. Here we explore whether this effect persists to high concentrations. Experiments Nuclear Magnetic Resonance (NMR) pulsed field gradient (PFG) techniques were used to measure shear-induced droplet diffusion for capillary flow of various water-in-oil (w/o) emulsions in a direction transverse to flow. Two adaptations were necessary – the acquired signal was analyzed so as to quantitatively distinguish restricted molecular diffusion within the emulsion droplets from shear-induced diffusion of the droplets, whilst flow-compensated PFG pulse sequences were shown to be necessary to account for any erroneous effects due to flow. A range of w/o emulsions were considered to enable measurement of shear-induced droplet diffusion as a function of both water content and mean shear rate. The surfactant content of these emulsions was adjusted such that they presented similar (stationary) emulsion droplet size distributions (DSD) which were also measured using NMR PFG techniques. Findings The droplet shear-induced diffusion data for the emulsion systems were compared against relevant results from the literature. Consistent with predictions for dilute systems, significantly greater droplet diffusion was measured relative to hard sphere suspensions at all concentrations, and a quadratic dependence was found between droplet diffusion and mean droplet size. For more concentrated emulsions, a peak in the droplet diffusion–concentration relationship was observed for the first time in emulsions, prior to the onset of emulsion inversion.

In the present work, Raman spectroscopy was used to study the structure of water molecules in the vicinity of glass particles with different hydrophobicity, immersed in water and in tetrahydrofuran and cyclopentane hydrates. The glass particle surfaces were clean (hydrophilic), coated with N,N-dimethyl-N-octadecyl-3-aminopropyl trimethoxysilyl chloride (partially hydrophobic), or coated with octadecyltrichlorosilane (hydrophobic). The Raman spectra indicate that, prior to nucleation, water molecules in the vicinity of hydrophobic surfaces are more ice-like ordered than those in the bulk liquid or near either hydrophilic or partially hydrophobic surfaces. Furthermore, the degree of hydrogen-bond ordering of water observed prior to hydrate nucleation, as measured by the ratio of the inter- and intramolecular Raman OH bands, was found to have an inverse relationship with the mean induction time for hydrate formation. Following hydration formation, no significant difference in the water molecule structure was observed in the hydrate phase based on their Raman OH bands, irrespective of surface hydrophobicity. These observations made with Raman spectroscopy provide the foundations for a quantitative link between hydrate nucleation promotion and water-ordering near solid surfaces, which could enable direct comparisons with results from corresponding molecular dynamics simulations.

Liquid irrigation is one of the key process control parameters following the construction of an ore leaching heap. This study uses 3D magnetic resonance imaging (MRI) to examine non-invasively the effect of liquid flowrate changes on heap hydrology when drip irrigation is used. Experimental results from a vertical column show that the increase in flowrate causes an increase in the number of rivulets in the ore bed. The new rivulets were found to be thicker, and their development caused an increase in liquid–solid contacting area which is considered advantageous for metal ion recovery. Experiments performed on larger samples showed that the effects of flowrate changes were limited to the region directly below the drip emitter because the increase in flowrate caused an increase in macro-pore flow and not capillary retention of liquid. Therefore the increase in flowrate was not found to perturb liquid distribution patterns in a way that would be substantially advantageous to heap leaching recoveries.

The stability of hydrate-in-oil dispersions is a critical parameter in assessing the risk of flowline blockage due to particle aggregation or wall deposition. Many studies of hydrate particle transportability have used deionized water to form the dispersion; however, the resulting lack of ions means that the crude oil’s natural surfactants will be less active, which does not represent production conditions. This study presents a new investigation of both hydrate-in-oil dispersion stability and water-in-oil emulsion stability, measured with a differential scanning calorimeter (DSC) and low-field nuclear magnetic resonance (NMR) apparatus, respectively. The results show that hydrate-in-oil dispersion stability increases directly with sodium chloride (NaCl) mass fraction in the aqueous phase; above 5 wt % NaCl, the dispersion was observed to be stable over ten hydrate formation–dissociation trials. This was comparable with the dispersion stability observed previously when an ionic surfactant was dosed at 2 w...

Kinetic hydrate inhibitors (KHIs) are polymeric based chemicals that delay the nucleation and/or suppress the growth rate of gas hydrate crystals. While KHIs have been used successfully to mitigate hydrate blockage risk during oil and gas production, the mechanisms by which they function remain unclear. In this work, multiple high-pressure stirred automated lag time apparatus (HPS-ALTA) were used to investigate the impact of a KHI on the subcooling formation probability distributions of methane hydrates and the subsequent initial growth rates. Over 3000 hydrate formation events were measured around 12 MPa using seven independent HPS-ALTA cells with KHI concentrations of up to 3 wt% in water. The addition of KHI made hydrate formation much less stochastic: significant reductions occurred in both the width of the formation probability distribution for a given cell, and in the offsets between distributions measured with different cells. Average initial hydrate growth rates were reduced by approximately a factor of 5 as KHI concentration increased, even though the average driving force (subcooling) increased by a factor of up to 3. However, above a KHI concentration of 0.3 wt%, a diminishing return was observed in both the nucleation delay and growth rate suppression. A Classical Nucleation Theory (CNT) framework was applied to investigate whether polymer adsorption onto active nucleation sites could explain the observed delay in formation onset. However, the CNT kinetic parameter extracted from the measured formation probability data increased with concentration, which is opposite to the dependence predicted by the polymer-adsorption model of nucleation suppression by KHIs.

The viscosity of {xCH4 + (1 – x)C4H10} with x = 0.9484 has been measured at temperatures and pressures in the range (200 to 423) K and (2 to 30) MPa, respectively, corresponding to densities between (20 and 371) kg·m–3. The measurements were made using a vibrating-wire-viscometer with the wire clamped at both ends and operated in steady-state mode with a combined relative uncertainty of 1 %. The viscometer was also used to investigate the ability of a vibrating-wire instrument to determine the upper and lower dew pressures of the mixture in the retrograde region at (263 and 273) K. The dew pressures were determined by identifying the point along an isothermal pathway at which the slope of the wire’s resonance half-width with pressure exhibited a discontinuity. At the upper dew pressures near 10 MPa the results were consistent to within 0.2 MPa of predictions made using the GERG-2008 equation of state (EOS), while at the lower dew pressures near 3 MPa the agreement was within 0.3 MPa. To facilitate future ...

Asphaltenes are the heaviest and most polar class of compounds in crude oil, which may precipitate out of solution due to changes in the pressure, composition, or temperature. During production, aggregation between asphaltene solids may lead to viscosification of the oil phase and/or deposition of the solids on the flowline wall. This study presents the first measurement of asphaltene interparticle cohesive forces using a micromechanical force (MMF) apparatus, which is similar to that used previously to investigate gas hydrate interparticle cohesion. Asphaltene solids were precipitated from two crude oils, and cohesive force measurements were performed for particle pairs with diameters ranging from 100 to 200 μm. In air, the measured cohesive forces between the asphaltene particles were approximately one-half of those measured between hydrate particles in cyclopentane-saturated nitrogen vapor. Asphaltene cohesive force was measured in liquid cyclopentane, to provide a comparison against cyclopentane hydra...

Benchtop nuclear magnetic resonance (NMR) pulsed field gradient (PFG) and relaxation measurements were used to monitor the clathrate hydrate shell growth occurring in water droplets dispersed in a continuous cyclopentane phase. These techniques allowed the growth of hydrate inside the opaque exterior shell to be monitored and, hence, information about the evolution of the shell's morphology to be deduced. NMR relaxation measurements were primarily used to monitor the hydrate shell growth kinetics, while PFG NMR diffusion experiments were used to determine the nominal droplet size distribution (DSD) of the unconverted water inside the shell core. A comparison of mean droplet sizes obtained directly via PFG NMR and independently deduced from relaxation measurements showed that the assumption of the shell model-a perfect spherical core of unconverted water-for these hydrate droplet systems is correct, but only after approximately 24 h of shell growth. Initially, hydrate growth is faster and heat-transfer-limited, leading to porous shells with surface areas larger than that of spheres with equivalent volumes. Subsequently, the hydrate growth rate becomes mass-transfer-limited, and the shells become thicker, spherical, and less porous.

ACL; International audience; A vibrating wire instrument, in which the wire was clamped at both ends, was used to measure the viscosity of xCO2 + (1 - x)CH4 with x = 0.5174 with a combined uncertainty of 0.24 μPa·s (a relative uncertainty of about 0.8 %) at temperatures T between (229 and 348) K and pressures p from (1 to 32) MPa. The corresponding mass density ρ, estimated with the GERG-2008 equation of state, varied from (20 to 600) kg·m-3. The measured viscosities were consistent within combined uncertainties with data obtained previously for this system using entirely different experimental techniques. The new data were compared with three corresponding states-type models frequently used for predicting mixture viscosities: the Extended Corresponding States (ECS) model implemented in REFPROP 9.1; the SUPERTRAPP model implemented in MultiFlash 4.4; and a corresponding states model derived from molecular dynamics simulations of Lennard Jones fluids. The measured viscosities deviated systematically from the predictions of both the ECS and SUPERTRAPP models with a maximum relative deviations of 11 % at (229 K, 600 kg·m-3) and -16 % at (258 K, 470 kg·m-3), respectively. In contrast, the molecular dynamics based corresponding states model, which is predictive for mixtures in that it does not contain any binary interaction parameters, reproduced the density and temperature dependence of the measured viscosities well, with relative deviations of less than 4.2 %. © 2015 Elsevier Ltd. All rights reserved.

The formation of oil-in-water dispersions is a critical step during the blowout of coastal and deepwater oil and gas production systems, and is a determining factor in the vertical and lateral migration of oil through the associated adjacent water column. In this study a high-pressure sapphire visual autoclave apparatus was used to measure the size of crude oil droplets that were saturated with gas and dispersed in an aqueous phase as a function of mixing speed. Oil-in-water droplet size distributions were measured at pressures of 11 MPa, for autoclave stirring rates of 200–1000 RPM (1076≤ Re stirred vessel ≤5378). Arithmetic mean droplet diameters decreased monotonically from 344 to 125 μm over this range, with maximum droplet sizes decreasing from 708 to 441 μm. A model tuned to the measured oil-in-water data was used to predict a mean droplet size on the order of 80 μm for Deepwater Horizon conditions; when incorporated into far field blowout simulations, this droplet size data enables quantitative assessment of the impact of dispersant injection at the blowout site.

The viscosity of {xCH4 + (1 – x)C3H8} with x = 0.949 was measured at temperatures between (200 and 423) K and pressures in the range (10 to 31) MPa using a vibrating-wire-viscometer with the wire clamped at both ends and operating in steady-state mode. Over these conditions the fluid mass density, which was calculated from the measured temperature and pressure using the GERG-2008 equation of state, ranged from (120 to 360) kg·m–3. A three-parameter polynomial in density was able to represent the measured viscosities, which ranged between (19 and 53) μPa·s, with an r.m.s. deviation of 0.47 μPa·s. This was comparable to the average combined uncertainty of the measurements (0.43 μPa·s), and no temperature dependence of the viscosity was resolvable within the experimental uncertainty beyond that incorporated within the density obtained from the equation of state. The viscosity of CH4 + C3H8 reported herein along with measurements previously reported in the archival literature at densities up to 500 kg·m–3 hav...

There are substantial economic and operational incentives to reduce the volumes of thermodynamic inhibitors (THIs) injected in deepwater oil and gas pipelines to a minimum threshold necessary to achieve a flowable hydrate slurry and prevent hydrate deposition; however, there is uncertainty about whether this underinhibited condition may worsen hydrate transportability and increase plugging potential. In this study, hydrate formation rate and hydrodynamic pressure drop were measured over a range of temperatures and subcoolings using a one-inch single-pass flowloop containing aqueous monoethylene glycol (MEG) solutions (0–40 wt %) at a liquid loading of 5 vol % and a synthetic natural gas at an initial pipeline pressure of 10.3 MPa (1500 psia). Measured average formation rates in this gas dominant flow were within a factor of 2 of the kinetic rate and about 250 times faster than that expected for oil dominant flows. When the system was underinhibited with MEG, the pressure drop behavior over time was consis...

The dispersion coefficient of displacing fluids within porous media is an important parameter to measure accurately for a range of applications. For example, enhanced gas recovery is an emerging technology where carbon dioxide is injected into natural gas reservoirs as a means of maintaining the pressure of the reservoir and to hence enhance the natural gas recovery, with the additional benefit of carbon dioxide sequestration. Research is currently being done to measure the dispersion coefficient of carbon dioxide into methane because carbon dioxide is a contaminant that reduces the value of the natural gas. Such dispersion experiments are difficult to perform in the laboratory using conventional rock core flooding equipment as erroneous contributions to the dispersion process from entry and exit effects (into and out of the rock core respectively) are impossible to eliminate completely. Previously, we have estimated the resultant error to be of the order of 25 % (Hughes et al., Int J Greenh Gas Control 9:457–468, 2012). Here we effectively deploy spatially resolved breakthrough curves which are characteristic of the dispersion process for carbon dioxide replacing methane. These are obtained from time-resolved 1D magnetic resonance imaging (MRI) profiles. By analysis of the additional dispersion between these time-resolved profiles, we are able to eliminate the entry/exit effects and obtain more accurate values for the dispersion coefficient. We demonstrate this using a model porous medium (mono-dispersed glass beads) in a cell capable of holding gas pressures up to 80 bar in a low-field MRI rock core analyser. Via simultaneous conventional IR analysis of the carbon dioxide effluent to determine the dispersion coefficient, we are also able to directly quantify the magnitude of the error due to these entry/exit effects.