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Benchtop NMR analysis combined with model-based fitting protocols can detect commercial honey adulteration down to 5 wt%.

Simulations of nuclear magnetic resonance (NMR) signal from fluids contained in porous media (such as rock cores) need to account for both enhanced surface relaxation and the presence of internal magnetic field gradients due to magnetic susceptibility contrast between the rock matrix and the contained fluid phase. Such simulations are typically focussed on the extraction of the NMR T2 relaxation distribution which can be related to pore size and indirectly to system permeability. Discrepancies between such NMR signal simulations on digital rock cores and associated experimental measurements are however frequently reported; these are generally attributed to spatial variations in rock matric composition resulting in heterogeneously distributed NMR surface relaxivities (ρ) and internal magnetic field gradients. To this end, a range of synthetic sediments composed of variable mixtures of quartz and garnet sands were studied. These two constituents were selected for the following reasons: they have different densities allowing for ready phase differentiation in 3D μCT images of samples to use as simulation lattices and they have distinctly different ρ and magnetic susceptibility values which allow for a rigorous test of NMR simulations. Here these 3D simulations were used to calculate the distribution of internal magnetic field gradients in the range of samples, these data were then compared against corresponding NMR experimental measurements. Agreement was reasonably good with the largest discrepancy being the simulation predicting weak internal gradients (in the vicinity of the quartz sand for mixed samples) which were not detected experimentally. The suite of 3D μCT images and associated experimental NMR measurements are all publicly available for the development and validation of NMR simulation efforts.

In subsea oil and gas production, a transition away from complete gas hydrate avoidance to risk-based hydrate management has the potential to offer cost savings and improved viability for new devel...

Reliable measurements of oil-in-water (OiW) content is essential in the oil and gas industry. The current OiW analysis techniques deployed in the industry need frequent calibration and mostly depen...

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...

NMR T2 relaxation times for fluids in a porous medium are, in principle, proportional to the relevant occupied pore size. Here, we exploit this relationship to monitor the pore size distribution oc...

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.

Gas hydrates are ice-like solids, which may form and aggregate in crude oil pipelines; in severe cases, the increase in frictional pressure drop may exceed the available driving force, resulting in a non-flowing (blockage) condition. In order to assess the severity of hydrate formation in oil- or condensate-dominant lines, a slurry viscosity model must be applied to, and validated for, hydrate-laden suspension. A well-known model, applied in industrial situations for hydrate slurry rheology has been suggested to significantly under-predict apparent viscosity during the early and intermediate stages of hydrate blockage formation. As hydrate particles suspended in the slurry may aggregate, this study interrogates their suspension rheology in two parts: the underlying suspension behavior was tested by injecting industrial anti-agglomerant (AA) chemicals, thereby identifying the contribution of particle aggregation for identical systems without AAs. A temperature-controlled high-pressure rheometer with a vane...

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...

We present a novel multiphase flow metering technique for simultaneous measurement of oil and water volumetric flowrates. An Earth’s field nuclear magnetic resonance (NMR) detection coil is applied to measure free induction decay (FID) signals of two-phase oil/water flows. A dual polarisation technique is introduced utilising an upstream permanent magnet as well as an electromagnetic pre-polarising coil. FID signals with variable pre-polarising conditions are acquired and fit with a model for the NMR fluid signal using a 2D Tikhonov regularisation algorithm, allowing determination of a joint 2D velocity-T1 probability distribution. Appropriate analysis of the measured velocity-T1 distributions allows calculation of individual phase flowrates. The performance of the NMR flow measurement technique is examined for oil/water flows which are visually observed to be in three different flow regimes: stratified flow with mixing, dispersion of oil-in-water and water, and full oil-in-water emulsions. Two-phase flow characteristic features such as velocity slip are examined for each flow regime. Finally the accuracy of the measurement system in each flow regime is validated against in-line rotameter measurements.

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.

We report subcooling-dependent measurements of hydrate formation on water droplets suspended via acoustic levitation in high-pressure natural gas. Ninety independent visual induction time measurements enabled the construction of induction time distributions with nucleation rates extracted at subcoolings of (12, 13.4 and 14.5) K. Using models from classical nucleation theory, kinetic and thermodynamic nucleation parameters were determined for freely suspended droplets and subsequently compared to those measured in more traditional stirred reactors. Scaling of the observed nucleation rates by each system’s gas-water interfacial area led to improved consistency between the datasets. However, we show that while hydrate formation rates in systems with solid containing surfaces are determined by a small number of nucleation sites with low nucleation work, formation rates in levitated droplets are set by sites that have higher nucleation work but are more numerous. This leads to distinct subcooling-dependencies for nucleation rates in the two systems. These results provide insight both into hydrate promotion and avoidance strategies that are relevant to multiple applications.

The effect of salinity on water-in-oil emulsions was systematically studied using a combination of nuclear magnetic resonance (NMR) pulsed field gradient (PFG) measurements of emulsion droplet size...

The tortuosity (τ), defined in the present context as the ratio of the free diffusion coefficient to the restricted diffusion coefficient of a contained fluid, is an important but difficult to measure characteristic of a porous medium, particularly when it is partially saturated with water. We develop and apply methodology, based on nuclear magnetic resonance (NMR) pulsed field gradient techniques, to measure τ for various sandstone rock cores as a function of residual water fraction. The NMR methodology requires the use of bipolar pulsed field gradient stimulated echo pulse sequences to avoid systematic errors due to magnetic susceptibility differences and D2O as a stationary immiscible water phase; this was selected as it provides no 1H NMR signal. Tortuosity of the free pore space was successfully measured using liquid ethane as a probe fluid for three different sandstones over the full accessible range of residual water saturation. Generally, the tortuosity was observed to increase with residual water (D2O) content; however, significant variations were observed between the different sandstones.

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.

The current hydrate kinetics model implemented in the multiphase flow simulator OLGA treats hydrate growth in oil-continuous systems by considering the solidification of emulsified water droplets to form a hydrate-in-oil slurry that is assumed to be stable. To date, the validity of this model has not been established for gas-dominant systems, where gas void fractions can exceed 90 vol %. Here, six experimental data sets, collected using a 40-m single-pass gas-dominant flowloop operating in the annular-flow regime, were compared with predictions made using the current hydrate kinetics model. The comparison identified discrepancies in the predicted flow regime and the gas–water interfacial area that significantly affect kinetic hydrate-growth-rate calculations; these discrepancies might be due, in part, to differences in dynamic similarity between flowloop experiments and industrial-scale simulations. By adjusting only the kinetic rate scaling factor, it was not possible to match the pressure drop observed ...

The development of kinetic hydrate inhibitor (KHI) performance rankings is essential for these chemicals’ implementation within risk-based hydrate management strategies. Here, we obtain high resolution induction time distributions and growth rate measurements with a high pressure, stirred, automated lag time apparatus (HPS-ALTA) to make rigorous comparisons between two industrial KHIs (Inhibex 501 and 713). These comparisons reveal performance rankings can be subcooling dependent, and that growth rate alone is insufficient for accurate screening. Application of a Classical Nucleation Theory (CNT) based model to these results suggests that nucleation in systems dosed with Inhibex 501 and 713 respectively occurs on 7 and 700 times as many sites as compared to KHI-free systems, while the nucleation work required at these sites is increased by a factor of 9 and 28. When combined with gamma distributions and fluid residence times, these measurements can help inform the operational risk assessment of a hydrate blockage.

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.

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.

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.

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...

Magnetic Resonance Imaging (MRI) velocimetry was applied to study non-invasively the water flow field inside a spiral-wound desalination membrane module (diameter: 2.5 in.; length: 18.5 in.), located in a pressure vessel, at typical practice operational conditions as a function of alginate fouling, simulating extracellular polymeric substances (EPS). Cross-sectional velocity images were acquired at an in-plane spatial resolution of 0.137 mm at multiple locations along the length of the reverse osmosis module and were acquired as a function of alginate concentration. At a total system alginate concentration of 3.25 mg/l, significant changes in the cross-sectional velocity map were observed near the module inlet due to alginate fouling, with limited changes observed in the middle and outlet regions of the module. When the total system alginate concentration was increased to 75 mg/l, it caused the module brine seal to fail resulting in significant local water flow by-passing the membrane module. This was clearly discernible in this opaque membrane system using MRI and resulting in dramatic changes in fluid velocity distribution through the membrane module. These observations of significant flow field heterogeneity as fouling develops are consistent with ‘irreversible’ fouling effects noted frequently in practice by the water treatment industry.

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 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.

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...

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...

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...

The formation of methane hydrate beds at the gas–water interface in a high-pressure visual autoclave apparatus, under both continuous cooling/flow and shut-in/restart operating procedures, was studied. Bed formation was identified by an increase in the measured resistance-to-flow of the hydrate slurry, and supported by visual observations. During continuous cooling/flow experiments, the hydrate volume fraction required to form a moving bed increased from 15 vol % to 40 vol % over a range of initial Reynolds numbers for the stirred cell of 280 to 4500. For shut-in/restart trials, the bed formation point increased from 6.6 vol % to 33 vol % hydrate over an equivalent, stirred cell Reynolds number range of 240 to 3900. No significant differences in the dependence of the bed formation point on shear rate were observed between the constant cooling/flow and shut-in/restart experiments, suggesting both systems evolved along the same pathway to hydrate plug formation. Some differences between the two types of exp...

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...