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Under high-pressure and low-temperature conditions, gas hydrate shells may form and grow at the interface of water droplets in water-in-oil emulsions. Such hydrate formation can enable downstream agglomeration and slurry viscosification, thus increasing the risk of hydrate blockage. Therefore, emulsion stability represents a critical parameter in understanding this overall flow behaviour. In this study, the impact of three common and widely-used industrial anti-agglomerants from three different suppliers (AA-1, AA-2 and AA-3—exact composition is commercially sensitive) on 30 wt% water-in-oil (W/O) emulsion stability was investigated. Bench-top nuclear magnetic resonance (NMR) pulsed field gradient (PFG) methods were used to measure the droplet size distributions (DSDs) of the W/O emulsions as a complement to bottle stability test. In the absence of hydrate anti-agglomerants, based on visual observation, 85% of the original W/O emulsion remained after 10 h. In the presence of AA-1 and AA-2, 94% of the original emulsion was retained; in contrast, AA-3 acted to destabilise the emulsion with only 64% of the original emulsion visually evident after 10 h. These results were substantiated by PFG NMR measurements which showed substantial changes in droplet size as a function of sample height for the W/O emulsion formulated with AA-3. Interestingly the W/O emulsion formulated with AA-1, while very stable, was characterised by comparatively very large water droplets, indicative of a complex multiple water-in-oil-in-water (W/O/W) emulsion microstructure. AA-2 forms stable emulsion with small droplets of water dispersed in the oil phase. Our results provide insight into a wide range of potential impacts of AA addition on an industrial crude oil pipeline, in which AA-1 resulted in a complex W/O/W multiple emulsion, AA-2 behaved as an emulsifier and AA-3 behaved as a demulsifier. [ABSTRACT FROM AUTHOR]

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. [ABSTRACT FROM AUTHOR]

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 CO 2 -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 CO 2 -rich hydrates. In this work, hydrate growth rate and resistance-to-flow (torque) data for a ternary CO 2 -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 CO 2 -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. [ABSTRACT FROM AUTHOR]

As industry moves toward the production of oil and gas resources in deep offshore environments, the prospective formation of natural gas hydrates under low temperature, high-pressure conditions poses an increasing risk of pipeline blockage. Successful management of this risk requires a precise forecast of the hydrate growth rate. Such predictions should incorporate quantitative descriptions of both deterministic and probabilistic hydrate phenomena. In this work, we present a first step towards such a quantitative risk assessment for systems that form hydrate slurries, based on a consideration of the stochastic nature of hydrate formation. Our framework introduces a new approach to risk assessment, by coupling a laboratory-derived probabilistic nucleation model with existing deterministic calculations for hydrate slurry viscosification. This new approach is used to extend a previously-described hydrate risk algorithm, the Hydrate Flow Assurance Simulation Tool (HyFAST), which enables the rapid assessment of hydrate slurry viscosification using the most advanced models available. Importantly, while the previous version of HyFAST was constrained to calculations in flowloop and autoclave geometries, for which it is sufficient to consider a single volume element, the new version of the HyFAST algorithm allows calculations for flowlines wherein a series of multiple volume elements are considered. The advanced hydrate formation models within this algorithm allow identification of critically important hydrate formation scenarios, and may serve as a screening tool for cases that then require study within rigorous hydrodynamic packages such as OLGA ® or LedaFlow ® to examine behaviour during key transient events. By coupling the outputs of our predictive algorithm and quantitative risk framework, we demonstrate a new capability to assess what constitutes an acceptable level of hydrate formation. We use this algorithm in a series of case studies that compare the effectiveness of common hydrate mitigation strategies over the life of a reservoir, including the optimization of a wellhead choke opening for both production rate and hydrate blockage risk. [ABSTRACT FROM AUTHOR]

• Anti-agglomerating characteristics of 2-butoxyethanol (BGE) is evaluated. • Substantial reduction in oil–water interfacial tension was observed with BGE. • BGE enhanced hydrate kinetics, but reduced agglomeration. • Synergistic inhibition effect of BGE + MEG was observed. To alleviate the severity of hydrate formation in subsea oil and gas pipelines, the injection of anti-agglomerants (AAs) is one of the promising approaches. In this work, we investigate the hydrate anti-agglomerating characteristics of 2-butoxyethanol, also called butyl glycol ether (BGE), which has been reported in the literature as an effective synergist for kinetic hydrate inhibitors (KHIs), and a solvent for low dosage hydrate inhibitors (LDHIs). In view of its hydrophobic and hydrophilic moieties, we evaluate the adsorption affinity of BGE for the oil–water interface employing the interfacial tensiometer (IFT) apparatus. Moreover, a micromechanical force (MMF) apparatus was used to probe the interfacial behavior of hydrate particles, wherein we measured the cohesive forces between cyclopentane hydrate particles in the presence of BGE at atmospheric pressure and 274.2 K. The kinetics of methane hydrate formation and resistance-to-flow were assessed while measuring the dynamic pressure–temperature data and motor torque signals alongside with visual observations, respectively, employing a high-pressure visual autoclave (HPVA). IFT results reveal the strong surface active properties of BGE with a substantial reduction in oil–water interfacial tension at ambient conditions. However, no considerable change in the cohesive forces between cyclopentane hydrate particles was observed through MMF measurements. In contrast, HPVA results reveal that the addition of BGE enhanced the kinetics of methane hydrate formation; however, the corresponding torque pattern/visual interpretations indicated an anti-agglomerating action of BGE. While synergistically combining the BGE with under-inhibited dosages of mono-ethylene glycol, we further demonstrated a significant improvement in the hydrate transportability, wherein this synergism led to a non-plugging scenario (flowable hydrate slurry). Our findings will offer new insights into the development of new anti-agglomerant chemistries. [ABSTRACT FROM AUTHOR]

• Statistically robust data for KHI impact on hydrate induction time probabilities. • KHIs modify induction time probabilities distributions from exponential to Gamma. • Data reveal how KHIs both delay formation and reduce crystal growth rate. • Mechanisms by which KHIs affect formation at various subcoolings elucidated. The formation of gas hydrates is crucial to many technological applications including energy production, energy storage, desalination, and CO 2 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. [ABSTRACT FROM AUTHOR]

An improved, high pressure, stirred automated lag time apparatus (HPS-ALTA) was used to determine gas hydrate nucleation and growth rates from induction time measurements at fixed subcooling. The improved HPS-ALTA uses multiple thermoelectric elements to allow rapid, radially symmetric heating and cooling, which together with the automatic detection of hydrate formation, makes feasible the measurement of statistically significant induction time distributions. Four induction time probability distributions, with between 83 and 312 points, were measured at subcoolings ranging from (6 to 9.7) K for water with a synthetic natural gas mixture at pressures around 12 MPa. The induction time data measured at each subcooling were exponentially distributed and were fit using a model derived from Classical Nucleation Theory based on the mononuclear nucleation mechanism. The nucleation rates obtained in this work were consistent within a factor of three or better with recent literature measurements made using a completely different apparatus. Hydrate growth rates measured at fixed subcooling using the improved HPS-ALTA were also found to be stochastic but consistent with previous measurements of the kinetic growth rate in a binary gas mixture. The results obtained here establish the need to improve theoretical models of hydrate formation to reconcile predicted nucleation rates with the much slower ones observed experimentally. [ABSTRACT FROM AUTHOR]

Gas hydrate formation is a stochastic phenomenon of considerable significance for any risk-based approach to flow assurance in the oil and gas industry. In principle, well-established results from nucleation theory offer the prospect of predictive models for hydrate formation probability in industrial production systems. In practice, however, heuristics are relied on when estimating formation risk for a given flowline subcooling or when quantifying kinetic hydrate inhibitor (KHI) performance. Here, we present statistically significant measurements of formation probability distributions for natural gas hydrate systems under shear, which are quantitatively compared with theoretical predictions. Distributions with over 100 points were generated using low-mass, Peltier-cooled pressure cells, cycled in temperature between 40 and -5 °C at up to 2 K·min-1 and analyzed with robust algorithms that automatically identify hydrate formation and initial growth rates from dynamic pressure data. The application of shear had a significant influence on the measured distributions: at 700 rpm mass-transfer limitations were minimal, as demonstrated by the kinetic growth rates observed. The formation probability distributions measured at this shear rate had mean subcoolings consistent with theoretical predictions and steel-hydrate-water contact angles of 14-26°. However, the experimental distributions were substantially wider than predicted, suggesting that phenomena acting on macroscopic length scales are responsible for much of the observed stochastic formation. Performance tests of a KHI provided new insights into how such chemicals can reduce the risk of hydrate blockage in flowlines. Our data demonstrate that the KHI not only reduces the probability of formation (by both shifting and sharpening the distribution) but also reduces hydrate growth rates by a factor of 2. [ABSTRACT FROM AUTHOR]

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. [ABSTRACT FROM AUTHOR]

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. [ABSTRACT FROM AUTHOR]

• Under-inhibited MEG indicates improvement in hydrate dispersion stability. • Synergistic combination of AA and under-inhibited MEG improves dispersion stability. • Natural and/or synthetic surfactants reduce both emulsion and dispersion stability. This study aims to determine any synergistic effect on hydrate dispersion stability by combining under-inhibited monoethylene glycol (MEG) with synthetic surfactants such as anti-agglomerants (AA). Hydrate dispersion stability describes the tendency of hydrate particles to remain dispersed without agglomerating in an oil-dominated system. The usage of under-inhibited MEG may result in hydrate agglomeration due to self-inhibited MEG that generates unconverted water during hydrate formation stage, contrary to the usage of AA which could improve stability of hydrate dispersion. Differential scanning calorimeter (DSC) was used to measure hydrate dispersion stability via integrated area of hydrate dissociation curves that reduces gradually during repeated hydrate formation-dissociation cycles. Unforseen improvement was recorded at MEG 1–3 wt% and synergistic improvement observed at AA 1 wt% with no further improvement at higher concentration. This reflects the presence of surfactants from natural and/or synthetic may prevent water droplets from coalescing and hydrate particles from aggregating. [ABSTRACT FROM AUTHOR]

• Rigorous extraction of nucleation rates from ramped temperature experiments. • Hydrate formation kinetics sampled at a wide range of temperatures. • Number of accessible nucleation sites grows with subcooling. • Results yield reliable predictions of hydrate formation probability in systems which experience a wide range of subcoolings. The formation of solids in the energy industry poses a threat to safety and reliability of operational facilities across numerous process stages. Experimental studies of gas hydrate formation probability are conducted under both fixed-temperature and ramped-temperature conditions. Although a method to extract nucleation rates from constant temperature measurements of induction time probability distributions is well established, extracting such rates from constant cooling data is complicated by the time-dependent driving force for hydrate formation. Here, we present and use a method for extracting the stationary nucleation rate as a function of temperature from constant cooling experiments based on the hazard function, which accounts for the system's history and the instantaneous formation probability. This method yields nucleation rates consistent with those measured using more time-consuming constant temperature experiments, while providing far more information about the underlying nucleation phenomena by sampling a wider range of temperatures. Measurements of methane hydrate formation probability obtained in well-mixed systems at 12 MPa with temperature ramp rates (1–3) K·min−1 were analysed using a framework based on Classical Nucleation Theory. The results suggest that the heterogeneous nucleation sites primarily responsible for the observed nucleation rate become more numerous and have higher average energy barriers as subcooling increases. This hypothesis is also consistent with recent experimental studies of systems containing kinetic hydrate inhibitors and provides a pathway to more reliable predictions of hydrate formation probability in production systems that experience a wide range of subcoolings. [ABSTRACT FROM AUTHOR]

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. [ABSTRACT FROM AUTHOR]

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. [ABSTRACT FROM AUTHOR]

[Display omitted] 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. [ABSTRACT FROM AUTHOR]

• A new five component model to fully quantify composition during CO 2 -CH 4 hydrate exchange. • NMR T 2 data suggest that the CH 4 hydrate generates preferentially in larger pores. • 1D MRI profiles show the phase saturations along the axis of the porous media. Clathrate hydrates sediments present significant potential as future clean energy resources; injection of CO 2 into these natural gas hydrate reservoirs to perform CO 2 -CH 4 hydrate exchange is an attractive approach for recovery of CH 4 in an approximately carbon–neutral manner. However, deployment of this approach is hampered partially due to the limitations of experimental techniques capable of providing in-situ, pore scale fluid and hydrate characterisation in these opaque sediments during this dynamic exchange process. Here we demonstrate a novel suite of NMR techniques to determine the in-situ composition during both CH 4 hydrate generation and subsequent CO 2 -CH 4 hydrate exchange in a model porous medium, predominately outside CH 4 hydrate stability zone but within the CO 2 hydrate stability zone. This was able to quantify the evolution in the amount of liquid water, CH 4 gas, CH 4 hydrate, liquid CO 2 , and CO 2 hydrate present in the porous medium respectively and hence directly determine the fractional recovery of CH 4 during exchange. These data were complemented by 1D magnetic resonance imaging (MRI) of the axial distribution of fluids in the sample and NMR relaxation measurements of fluid pore size occupation. This revealed preferable formation of CH 4 methane hydrate in comparatively larger pores; however subsequent CO 2 -CH 4 exchange was observed to preferentially occur via comparatively smaller pores containing transient liquid water. Hence we demonstrate the ability of MRI and NMR to provide both quantitative in-situ composition analysis as well as pore-scale occupation data which will enable future systematic studies of this complex exchange process. [ABSTRACT FROM AUTHOR]

[Display omitted] • CO 2 hydrates formed above and inside a water phase differ in morphology and stability. • The dissociation of hydrates inside the water phase is affected by both heat and mass transfer. • A 0.2 mm thick low porosity hydrate film at the original water-CO 2 interface was detected by MRI. • CO 2 hydrate film are supported by hydrate dendrites and sink when these dissociate. Gas hydrates are widely considered as promising candidates for gas storage, energy transportation and seawater desalination. Critical to such applications is a detailed 3D understanding of hydrate formation. To this end, we employ magnetic resonance imaging (MRI) to non-invasively image the gradual formation of opaque hydrate from CO 2 and water in a cylindrical vessel at 1 °C and as a function of pressure between 2.0 and 3.5 MPa. A 200 µm thick dense hydrate layer is consistently observed to form at the gas-water interface accompanied by a ~1.4 mm thick porous hydrate layer above it and frequently complex dendritic hydrate formation in the water phase below it. Dissociation is observed to occur preferentially via the thick hydrate layer with the initial hydrate film retained largely intact for an extended period of time. The sequential images of hydrate dissociation inside the water phase are most consistent with a vertical heat and mass transfer controlled hydrate dissociation process. The observed difference between the hydrates formed above and inside the water phase is of mechanistic value in understanding these complex interfacial phase transitions. [ABSTRACT FROM AUTHOR]

• Performance of two KHIs tested via induction times and hydrate growth rates. • KHI performance can be subcooling dependent. • Data matches previous result that KHIs yield gamma-distributed induction times. • Gamma distribution fits can be used to estimate formation risk for an application. 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. [ABSTRACT FROM AUTHOR]

• Hydrate nucleation & growth studied in a high pressure stirred automated lag time apparatus. • Impact of kinetic inhibitors on formation probability & growth distributions quantified. • Data allow differentiation between KHI functional mechanisms in classical nucleation theory. • Concentration dependence of nucleation and growth allow KHI benefit-cost assessment. 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. [ABSTRACT FROM AUTHOR]