Hydrates are crystalline water compounds that may form in deepsea pipelines and have the ability to quickly and efficiently plug flow. Given this issue, gas hydrate formation tests have been conducted and reported in a number of published articles. However, most published data has focused on continuous "steady-state" operations and a gap exists for the more complicated, yet interesting transient shut-in/restart scenarios. Motivation to study such systems are further exacerbated given that industrial fields can operate outside the gas hydrate formation region during continuous production. Hydrates become a major concern especially during unplanned shutdowns and restarts. Therefore, this work focuses only on hydrate transient results. Industrially relevant scenarios are investigated by looking into gas hydrate formation and its effect on fluid transportability through visualization and pressure drop during shut-in and restart in a laboratory-scale flowloop. The effects of parameters such as water content and dispersion state, shear, chemical injection, and oil properties on hydrate formation under transient conditions are reviewed and general agreement is shown between the studies. Overall, the general consensus is that lower water contents, dispersed water, high shear, thermodynamic inhibitor injection, dosing of anti-agglomerants or kinetic hydrate inhibitors, higher oil viscosities, and oils with natural chemical surfactant properties can be favorable for ensuring successful restart of hydrate forming systems. Flowloop tests in a gas-dominated system show that film growth over and around the liquid pool at the bottom of the pipe could lead to plugging in a significant portion of the flowline. This could continue to build up over time (with the addition of fresh hydrate forming materials in an actual system) and inhibit gas flow. Further tests on an oil-dominated system with an intermediate water content demonstrate how shut-in conditions could potentially increase the risk of plugging compared to dispersed lower water content systems. In the former case, water accumulation to low spots in the flowloop allowed for localized areas of high water concentration, where rapid hydrate bed formation in partially dispersed oil-water sections controlled the overall fluid transportability.

Loss-of-well-control (LOWC) events are generally defined as uncontrolled flow of formation or other fluids to either the surface or another subsurface formation. Such events are also known as blowouts. Blowouts can result in the loss of human life, catastrophic damage to ecosystems, and substantial economic losses. Many blowouts start with a "kick event", where the formation pore pressure becomes greater than the wellbore pressure, causing formation fluid to flow into the wellbore and combine with the drilling fluid (i.e., mud). Detecting a kick as early as possible is key to preventing a blowout. Conventional kick detection methods (e.g., monitoring mud pit returns, monitoring wellbore liquid levels) are usually time-consuming, resulting in delays during which the kick may grow in intensity and efforts required to re-establish well control may become more extensive. Some, more sophisticated kick detection techniques use instrumentation that can be costly. In this paper, an alternative, lower-cost, early kick detection method is proposed. Here a kick detection method is proposed that uses measurements from the instrumentation deployed on the drillstring to provide real-time information on the wellbore. Specifically, bulk density, acoustic (compressional wave) velocity, and electrical resisitivity are considered for use as detection parameters. These fluid mixture (combined formation and drilling fluid) properties as a function of kick fluid volume are estimated. Theoretically, these parameters are found to be sufficiently responsive to be used for kick detection. However, additional work is needed to determine how these parameters respond in experimental or field conditions.

The performance of a transient multiphase flow simulator was evaluated using high-quality field data measured in a large diameter gas-condensate offshore production system during different operating conditions (pigging, production shut-in and restart, production ramp-up, quasi steady state). Production data included measurements recorded from more than 120 sensors (pressure, temperature, flow rate, monoethylene glycol (MEG) fraction, slug catcher volume) during a three-year production time span. After thorough data screening and analysis, 19 distinct subsets encompassing both steady state conditions and at least one pigging event per subset were selected as benchmarks for validating simulation results. For each subset, a simulation model was developed to account for ambient and operating conditions, fluid properties, bathymetry profiles, thermal insulation and pipe burial, and hydrate inhibitor tracking (MEG). A comprehensive statistical analysis comparing predicted and measured pressure drop, pigged liquid volumes, outlet temperatures, and rich MEG mass fractions over the three-year time period demonstrated that the simulator predictions were in good agreement with the field data. The analysis included an uncertainty assessment of the measured production flow rates and volumes to better estimate the simulator accuracy. It was found that the simulator predicted both the cumulated rich MEG and condensate volumes received at the delivery point within the measurement uncertainty. The predicted rich MEG fractions at delivery were also in good agreement with the measurements, underlining the reliability of the inhibitor tracking module of the simulator. The pig travel time and the total liquid volume displaced by the pig during each pigging event were the main parameters considered to evaluate the accuracy of the simulator; both were predicted within a 10% error margin. Multiphase flow simulators are often developed and tuned against experimental data recorded in small to medium diameter scale pilots. The opportunity to validate a transient multiphase flow simulator against measured operating conditions in large diameter pipelines over an unprecedented three-year time span is valuable, not only for quantifying the performance of the simulator, but also for assessing its scalability.

Vertical upward multiphase flow through a blowout preventer (BOP) during a gas kick event produces complex fluid flow transients. Further complicating these transients is the fluid phase interactions during BOP closing event. The resultant pressure and flowrate transients are critical parameters that influence the BOP design and should be used to estimate if the BOP can close-on/control a kick event. In this paper, a hydro-mechanical two-phase flow model is developed to predict the fluid pressure and flowrate conditions for fully open and closing BOP during a gas kick. The case of a 20,000 psi reservoir is investigated along with a wel depth, from the rig floor to the borehole, ranging from 10,000 ft to 20,000 ft. The results illuminate the dependence of model-based BOP pressure rated design on the formation productivity index during a gas kick event. Furthermore, using a model-based approach for determining such information is essential in the development of next generation pressure control equipment standards and equipment certification, risk minimization to drilling crew and rig assets and reduction of well intervention frequency. High pressure definition based on pore pressure and/or BOP rated working pressure are discussed as well.

The ensemble Kalman filter (EnKF) algorithm is an elegant and effective method to optimize model parameters based on differences with predictions of model and measurement data. Great progress has been accomplished using EnKF for data assimilation within reservoir modeling during the last two decades. A typical example where data assimilation is necessary is history matching—the process of adjusting the model variables to account for observations of rates, pressure, saturations, and other variables. In contrast, much less attention has been given to flow model optimization for other workflows, such as drilling, production, flow assurance, and well testing. Providing two examples of applying the EnKF for real-time quantification of sensor-generated data is the aim of this paper. These examples include the analysis of the declining production curve and zonal pressure sensor data for evaluating matrix permeabilities and processing the multichannel optical to monitor the cleanup of hydrocarbon fluid samples during formation-tester sampling. Additionally, how the EnKF algorithm can be successfully applied to segmented multichannel sensor field data obtained from multichannel optical density sensors exhibiting the gradual transition from oil-based mud (OBM) filtrate to native formation fluid during formation-tester sampling stations is discussed. A simple algebraic proxy model is used to predict the decline of the volumetric fraction of OBM filtrate with time during formation-tester sampling. To implement and test the algorithm, a proof-of-concept MATLAB code was developed. Synthetic (simulated) pressure flow rate data were used for the production decline case while the actual field data from eight channel optical sensors were used for the formation-testing case. Model runs were performed in 50 to 60 combinations of model parameters, which were normally distributed around the best-guess values at the initial step. For both cases, only two to three iterations of the algorithm were sufficient to obtain values of the matching parameters.

This study provides valuable insights into hydrate management strategies as the industry transitions away from complete hydrate avoidance, particularly for the development of deep-water reservoirs with stricter economic margins. Transient simulation tools, such as the deployed hydrate deposition model, extend our ability to estimate blockage likelihood from heuristics to quantitative predictions. The model is applied to an insulated subsea tieback to identify the optimal no-touch-time (NTT) and depressurization pressure (DPP) following an unplanned shutdown. Two water-production scenarios are considered, from the lowest expected to the highest manageable rates. A complete hydrate blockage is predicted when the NTT was extended several hours beyond the nominal value for the highest water-to-gas ratio (WGR). Complete blockages are predicted for both low and high WGRs when the flowline is only partially depressurized, however, longer cooldown times for the high WGR case (due to greater volumes of residual liquids) meant a blockage took more than twice as long to occur than for the low WGR case. Fully depressurized restarts are both difficult and time consuming, leading to hydrate volume fractions (with respect to the pipe volume) exceeding 30 vol.%. An alternative hydrate management strategy is identified for cases with high volumes of water production, in which the flowline is only partially depressurized once the nominal NTT has elapsed, utilising the increased heat capacity of residual liquids. This reduces the quantity of gas sent to flare and simplifies the restart procedure.

Asphaltenes represent the most polar solubility fraction of crude oil. The polar-polar interactions between asphaltene-water, asphaltene-clay, or asphaltene-asphaltene molecules can cause severe flow assurance issues in the oilfield such as formation of highly stable emulsion, pore-throat blockages within the reservoir, and plugging of production and transportation flowlines. A novel approach of understanding these polar interactions through thermo-electric measurements is presented in this study, which can evaluate overall asphaltene stability in native crude oil. Most of the techniques currently being used to assess asphaltene stability and efficiency of different asphaltene inhibitors on preventing asphaltene deposition are based on light scattering and transmittance phenomenon. Since crude oils are intrinsically dark colored, these techniques require dilution of the oil sample with solvents like toluene and xylene or precipitants like pentane and heptane. Addition of these chemicals alters the nature and thermodynamic equilibrium of crude oil solubility fractions. Thus, a novel approach of measuring the thermo-electric properties of crude oil and crude oil-asphaltene inhibitor mixtures was developed and tested using a custom-built capacitor setup. The thermo-electric measurements were conducted on 10 different crude oil samples. These samples were altogether tested with 10 asphaltene inhibitors (AI). Measured data was used to indirectly estimate the polarity of the test sample, which is related to the dispersion efficiency of the asphaltene inhibitor. A standard light scattering technique was also used to analyze the oil and oil-inhibitor samples and the results were compared to the thermo-electric method outcomes. It should be noted that some of the oil samples tested in this study were obtained from production systems having asphaltene deposition issues and undergoing effective prevention and remediation treatment. Therefore, it is important for the success of the new technique to not only correlate with the standard light scattering test results but also be able to precisely the efficacy of asphaltene inhibitors for each of the test oil samples. From the results obtained, it was observed that using the thermo-electric method, the asphaltene inhibitors can be accurately screened for all the oil samples and the inhibitor efficiency analyzed in terms of its dosage curve, also agrees well with the conditions observed in the field. A strong correlation between the results obtained from the thermo-electric technique and the light scattering method indicates the validity and higher-level accuracy of the innovative technique. Moreover, direct application of this method on the production platform at the well-head using the native crude oil sample highlights the versitality of this novel method. In addition to testing overall asphaltene stability and inhibitor efficiency, the method can also be used to monitor and optimize the field scale production scenario.

Recently the concept of "no external gas hydrate control measures" has been proposed, whereby gas hydrate formation can occur in oil and gas subsea pipelines during steady state and transient operations, with the operational window defined by predictive analytic tools. Flow assurance engineers routinely use computer programs, including transient multiphase flow simulators coupled to a gas hydrate kinetics model to simulate gas hydrate formation and transportability. Given the complexity in multiphase flow modeling, modern machine learning technologies, especially artificial intelligence, could be applied to solve high-level, non-linear problems, such as evaluating gas hydrate risk based on measurable process parameters. In this work, several machine learning techniques, such as regression, classification, feature learning with an algorithm/framework like support vector machine (SVM) and neural networks (NN), are applied to analyze the data sets on: 1) hydrate tests conducted at pilot-scale flowloop facilities (4,500 data points), as well as 2) transient operation field data. The classification/regression model based on flowloop test data uses several independent input variables (features), such as water cut, gas-oil ratio, hydrate particle cohesive force, fluid velocity, oil viscosity, specific gravity, interfacial tension, and time in the hydrate stable zone, to output the hydrate fraction and probability of hydrate plugging in the pipeline. The semi-supervised learning model was applied based on the field data use as input, including water cut, shut-down time (where applicable), and gas-oil ratio to determine the level of hydrate resistance to flow during restart or dead oil displacement after production shut-down. The flowloop based machine learning model exhibited good prediction accuracies in test and validation processes, and was used to assess the hydrate risks in an actual field. The field data based machine learning model demonstrated the ability to construct field risk maps. The machine learning technique could be potentially applied in hydrate management to evaluate hydrate risks in subsea oil/gas pipelines. As a complement to more complex transient multiphase flow simulations, this machine learning approach can aid in the development of advanced hydrate management strategies.

One of the most promising Enhanced Oil Recovery (EOR) methods is CO 2 injection. However, if the oil contains asphaltenes, CO 2 injection may cause asphaltene precipitation and introduce production related challenges. Conventional three-phase (gas/oil/water) compositional simulators are unable to predict precipitation of asphaltenes and multiphase compositional simulators are required. The use of detailed multiphase equilibrium calculations is very CPU intensive and commercial simulation packages often employ a hybrid model that may not capture the true physics at play. Conflicting findings have been reported from experimental and theoretical studies: Some studies show that Asphaltene deposition, due to CO 2 injection, takes place near the injection well, while others have reported that asphaltene deposition occurs near the production well. True multiphase equilibrium calculations can be used to demonstrate that both findings are possible and that many factors will affect the deposition behavior. Accordingly, a general statement such as CO 2 injection causes more asphaltene precipitation relative to hydrocarbon (HC) gas injection is not always true. This added complexity indicates the need for multiphase compositional simulation to delineate asphaltene deposition behavior and quantity. In this work, we propose a four-phase compositional simulator (gas/oil/asphaltene/water) to predict the asphaltene precipitation during CO 2 and HC gas injection processes. A new hybrid formulation, based on a simple table look-up approach, is introduced to replace detailed multiphase calculations (gas/oil/asphaltene) at a CPU requirement that is comparable to two-phase (gas/oil) equilibrium calculations. A range of simulation models/scenarios are presented to test and validate the new formulation against detailed multiphase compositional simulation, and we demonstrate an excellent agreement between the hybrid model and the full multiphase calculations. The proposed approach is easy to implement in commercial tools and provides a path to allow for more detailed studies of asphaltene precipitation and related production challenges.

Gas hydrates forming in deep water subsea tiebacks can stop production of offshore wells by blocking the pipeline. This is considered one of the most challenging problems in flow assurance. In this work, we present a transient hydrate simulation tool with the ability of predicting hydrate formation in oil-dominated systems and the purpose of capturing the complicated multiphase flow scenarios that occur in oil and gas flowlines. This modeling tool can be applied to estimate hydrate formation in flowlines with different water cuts, which is especially useful in modeling transient shut-in/restart operations. A field case is used as a benchmark to verify the prediction performance of the proposed hydrate simulation model. The geometry, fluid properties and production data from an offshore well is reproduced using the hydrate formation model, quantifying hydrate formation and estimating plugging risk at different liquid holdup, water cuts and produced gas-oil ratios. Hydrate anti-agglomerant chemicals were used in this field case, and are considered in the simulations of steady state and shut-in restart operations. The proposed transient hydrate prediction model successfully predicted the formation of hydrate plugs as observed in the real field. This hydrate formation simulation tool can be applied for the design and optimization of prevention, management and remediation procedures of hydrates in flowlines.

Subsea boosting has today achieved a significant track record and it has been recognized by major oil companies as an important part of enhanced drainage strategies. For gas fields compression is the only viable means of artificial lift and subsea compressions offers many advantages over conventional topside compression such as increased ultimate recovery. The advantages of subsea compression increase with increasing tie-back distance. Particular features and benefits of subsea multiphase or wet gas compression are discussed in general and the particular experience with a subsea wet gas compression system now in operation at the Gullfaks field on the Norwegian continental shelf is presented. Commissioning of the Gullfaks Subsea Wet Gas Compression System started in 2015. The system ran for one month but had to be taken out of operation for almost two years due to umbilical leakage. The system was restarted in 2017 and has been running successfully ever since, boosting wet gas and increasing the production from several wells. The system flexibility is exploited in a more extended way then ever expected during the project phase, and allows the operator to take advantage of many opportunities including increased oil recovery, and kicking off dead wells and enabling stable well back-pressure. The fundamental benefits of subsea compression are now demonstrated.

It is critical to minimize the amount of free hydrocarbon entrained in the aqueous phase (i.e., Produced Water or Rich Monoethylene Glycol (MEG) streams) in order to mitigate impact on the operational performance of the Effluent Water Treatment and MEG Recovery Unit facilities. Hydrocarbon entrainment in Produced Water or Rich MEG is often the result of process conditions that favour emulsion formation and/or hinder emulsion separation. Consequently there is a need to look at the process and equipment design employed, along the flow path that the hydrocarbon/aqueous phase travels through, prior to entering the separation equipment used for hydrocarbon removal from the aqueous phase, as well as the separation equipment itself. The paper will present a roadmap of the overall route that the aqueous stream can take to offer insight into the process units affected by improper hydrocarbon removal. Operational situations arising from the impact of excessive hydrocarbon entrainment will be given as well as a summary of wellhead operating parameters that need to be considered in terms of their impact on equipment selection/design. The flow path, to be focused on, starts at the reservoir/wellhead and ends where the aqueous stream leaves the final hydrocarbon removal equipment, just upstream of either the Effluent Water Treatment or MEG Recovery Unit facilities. Factors concerning emulsion formation and separation are introduced as required to describe how process fluid properties and flow conditions influence the formation of emulsions and the separation of hydrocarbons from the aqueous phase. How to improve on existing methods for the selection/design of liquid-liquid separators by considering and trying to estimate the entire droplet size distribution (DSD) of the dispersed phase in the stream entering the separation equipment, along with estimating the amount of coalescence, will be elaborated on. This is paramount to ensure the correct equipment is selected, especially when the low end of the distribution, particularly drops below 20 μm, can be quite difficult to remove. Design considerations to minimize hydrocarbon content in the aqueous phase will be discussed and involve looking at key areas of energy dissipation (e.g., choke and control valves) regarding the range of fluid properties and process conditions, and the estimation/influence of drop size distribution/fractional interface coalescence efficiency ( f ICE ) on the selection/sizing of fluid-fluid separator technology. Examples of dealing with emulsion issues occurring in industry, as per vendor experience, will be presented as well as available vendor equipment technology. General recommendations concerning lab bench testing, modelling, and equipment/chemical vendor testing will also be discussed.

Blowout Preventer (BOP) is an integral component of defense in depth approach adopted in deepwater drilling operations. Regulatory bodies require frequent testing of these barriers, to make sure that they will be available to perform their intended functions when demand arrives. As BOP works only in demand mode, therefore the calculation of average probability of failure on demand (PFD avg ) is one of the technique that can provide the critical information about the availability of these barriers. In this study PFD avg formulation is used to carry out s systematic performance evaluation a BOP's barrier elements. A sensitivity analysis is also performed to account for some of the real demand conditions that cannot be tested during routine tests, an example is the testing of shearing capability of blind shear rams. Multilevel test formulations are used that accommodates both of proof test and partial stroke testing concepts. The interdependency of these barrier elements is modeled by using beta factor model, which account for common cause failures. The results are presented for three flow paths of open wellbore flow, flow through drillpipe-casing annulus and flow through drillpipe. Corresponding BOP's barrier elements are used to estimate the availability of these barriers when they are demanded. The analysis results indicate high common cause failures of BOP's main control system with an average value of 0.25. Which is a significantly high dependency of both of the BOP's control pods on some of the common elements that can fail them simultaneously. The results also show that average availability of drillpipe-casing annular and open-hole barrier channels is dominated by the BOP's main control system, mainly due to its high failure rates. The analysis also revealed that a beta factor contribution significantly impacts the unavailability of drillpipe-casing annular channel barrier elements. Results for other demand scenarios and combination of working of these barrier elements are also presented. The presented results highlight some of the critical safety measures of BOP's barrier element performance and also highlight some of the deficiency areas that need to be taken care of to improve the system's performance. It is therefore hoped that the presented results will be helpful to gain insight into different modes of operation and in improving the system's performance.

In this paper, we will highlight some of the impactful collaborative efforts completed within DeepStar Phase XII of the X200 Flow Assurance committees leading to the development, integration and deployment of novel technologies. This project aims to establish in what cases asphaltene deposition in reservoirs is a real problem. Flow reduction can occur in deepwater wells, which manifests as effective "skin" or high pressure drawdown required for fluid flow to be maintained. It is typically concluded, without additional evidence, that such problems are the result of asphaltene deposition. Some models for asphaltene deposition were developed between 1990 and 2005. However, the principal obstruction to validation of these models has been a credible core flow test to show increased flow restriction with depositing asphaltenes. At present, operators are unable to estimate the risk of development due to asphaltene deposition in reservoirs and the perceived flow impairment. To best assess the treatment frequency and effectiveness that is required for project development and execution, there is a need to be able to correctly predict the rate of formation damage in reservoirs from asphaltene deposition and develop effective remediation treatments. A successful project will provide test protocol, results, and analysis tools that can be applied to risk management evaluation for asphaltene fouling in reservoirs. Asphaltene precipitation and deposition in the production tubing and surface facilities is a well- documented issue and different methods are available to manage this problem. However, the problems that asphaltenes may cause in the reservoir, especially in the near-wellbore region, are much less understood. There is a lack of experimental capability to properly identify this problem and evaluate the corresponding potential strategies for prevention and/or remediation if/when needed. In addition, the available modeling tools to account for this problem have limited capabilities. Within this project, we aim to develop experimental procedures and modeling methods to establish whether impairment caused by asphaltene deposition in reservoirs is a real problem or not, and to develop an understanding of the mechanisms by which asphaltene precipitate, alter wettability and potentially deposit in the formation obstructing flow. A new experimental setup for Saturates, Aromatics, Resins, and Asphaltenes (SARA) characterization was designed and implemented in the lab to perform faster and more reliable analyses. Core flood experiments have been designed and successfully executed to induce the precipitation of asphaltenes inside the core upon addition of an asphaltene precipitant (e.g., n-pentane or n-heptane), which is crucial to obtain more meaningful and more representative experimental conditions. It has been observed that when n-pentane is used to precipitate asphaltenes, even though asphaltene aggregates are present in the system, the core flood test results do not show apparent damage to permeability. However, when asphaltenes are precipitated upon addition of n-heptane, aggregates have a more solid-like structure, which in turn have more tendency to block the pore throats. A microfluidic device was developed and used to visualize asphaltene deposition in porous media, at ambient pressure and different temperatures, flow rates, and driving force of asphaltene precipitation. The test results obtained from microfluidic device are in good agreement with the test results from the core flood experiments. A Computational Fluid Dynamic model based on Lattice-Boltzmann theory was developed to simulate asphaltene deposition inside porous media and is being validated for the capability to scale up lab results to field conditions.

Managing mature fields effectively and efficiently requires monitoring changes in formation fluid saturations as well as production from individual wells. Reservoir saturation monitoring is usually performed using slim pulsed neutron logging (PNL) tools because they can be deployed through tubing and operate in different modes, thus providing a wealth of information. However, several environmental factors can complicate the analysis, including complex completions and unknown or variable borehole fluids (gas in particular), which affect the PNL raw measurements and computed outputs. Factors related to the nature of the reservoir, such as complex lithology and multiple fluid phases, further complicate the analysis, making accurate fluid saturation evaluation and reservoir fluid-front mapping very challenging. An innovative pulsed neutron technology, recently introduced in the UAE, can help in reducing the evaluation uncertainty. The new device is fitted with multiple detectors and is used with newly developed algorithms to provide self-compensated formation sigma and hydrogen index (HI) measurements, overcoming many of the limitations of previous devices in complex environments. Additionally, the new tool provides a new formation property sensitive to gas-filled porosity, called the fast neutron cross section (FNXS), which, in adequate conditions, can be used to complement the analysis or highlight gas in the absence of openhole logs. The new PNL tool was run for the first time in an offshore UAE mature field targeting Jurassic formations. The production in the field started in the 1960s, followed in the 1970s by down-flank injection of water with much lower salinity than the connate water, and in the 1990s by crestal gas injection. The Jurassic reservoir mineralogy is a complex mixture of calcite, dolomite, and anhydrite. Completions consist of multiple combinations of tubing, casing, and hole sizes along with packers and other hardware components; often the borehole is filled with gas across the zones of interest, which has proven an obstacle to PNL interpretation. The new PNL device was tested in several wells in which it operated in inelastic gas, sigma, and HI (GSH) mode and carbon/oxygen (C/O) mode. Integration of all the recorded information made possible to reliably track the three-phase fluid saturation changes even in the gas-filled wellbores with complex completions. An additional benefit with the new tool was that because the C/O data were recorded at a speed twice as fast as that of the previous-generation PNL tool, it was possible to acquire the logs in the limited allocated time to help resolve the oil saturation in reservoir zones with variable salinity. The saturation analysis was compared to production logs and well production data where available.

Separator's performance with various droplet distributions is experimentally investigated in the pilot scale of facility. The mixture of continuous oil and dispersed water without surfactant is continuously re-circulated in the facility. The droplet distribution is produced by the operation of pumps and mixers through breaking up mechanism. Dispersion band above interface level appears in the condition of high dispersion fraction around 30%. The measured CLD from FBRM is converted into PSD by a peeling method and its converted PSD is changed again into volume-based PSD. Droplet distribution at the inlet reveals that the Sauter mean diameter is proportional to the maximum stable droplet (d 95 ) of volumetric distribution and its value reduces according to increasing watercut. The moments of distribution such as standard deviation, skewness, and kurtosis also show a linear relation with maximum droplet size. The actual cutoff diameter derived from WiO at the oil outlet is estimated around 50μm, which is much smaller than 250μm of cutoff diameter estimated from the Stokes' settling law. It implies the possibility of interaction among droplets inside separator in the condition of large dispersed phase. Actual cutoff diameter and remained water fraction seem to be weakly correlated with the parameter of specific surface area. The measured separator's performance reveals that inlet distribution in high dispersed phase seems to be not valid to estimate separator's performance due to the droplet distribution change in the separator.

In this work, the effects of an anti-agglomerant (AA) and salt (sodium chloride, NaCl) on water-in-oil (w/o) emulsion stability with and without the presence of gas hydrates is presented. The characteristics of gas hydrate formation and the hydrate slurry transportability were determined using a high pressure autoclave cell, with continuous mixing. The stability of the emulsions was independently measured by performing bottle tests, where the stability of the emulsion was determined by observing any evidence phase coalescence for a period of one week after emulsification. In addition, the stability of the emulsion with hydrate formation and dissociation was tested using high pressure differential scanning calorimetry (DSC). From high pressure autoclave studies, it was observed that the formation of a stable emulsion was shown to with the subject oils led to transportable hydrate slurries. Note however, it was observed that for this specific oil at 75 vol.% water cut and the addition of both AA and salt, a highly viscous mousse with viscosity of ~100 000 cP formed when the emulsion was saturated with methane gas at 950 psia and 20 °C. Even without the presence of hydrate, the formation of a highly viscous mousse may not be desirable in the field production system since it could render the system inoperable (effectively plugged). Interestingly, it was observed that the highly viscous mousse produced dispersed slurry of hydrates upon hydrate formation. Based on the autoclave studies, the absolute motor current (which indicates the relative viscosity of the system) at maximum amount of hydrate is 2 times lower of its original viscosity.

Gas hydrates can form in subsea oil and gas flowlines, where the depths of seawater and ocean conditions provide the thermodynamic environment for hydrate stability. Hydrates present a major flow assurance problem due to the relatively fast timescales at which they can form, grow/agglomerate, and plug a flowline. The common strategy for preventing hydrate formation uses thermodynamic inhibitors (THIs). However, THIs can be cost prohibitive or impractical as the water content in the flowline and its seawater depth increases. Therefore, there is growing interest in the use of alternative hydrate management strategies, such as the injection of low dosage hydrate inhibitors (LDHIs), which are active at considerably lower concentrations than THIs (e.g. 2 vol.% of LDHI versus 50 vol.% of THI). Anti-agglomerants (AAs) are a type of LDHI that prevent agglomeration and allow hydrates to flow as a slurry in oil and gas subsea flowlines. Before field deployment, AAs are screened and selected using laboratory set-ups, mimicking field conditions, in order to evaluate their performance and determine the effective dosage. Current hydrate agglomeration characterization methods implemented in the industry are non-uniform and qualitative, which can lead to conservative recommendations. In this work, the possibility of quantifying hydrate agglomeration in the presence of AAs is investigated, along with studies of the mechanisms via which AAs may operate. One mineral oil and two crude oils were used with a commercial AA in a high pressure stirred autoclave, equipped with particle imaging probes. Motor current input at a fixed RPM was monitored throughout the experiments and serves as an indicator of relative viscosity of the hydrate slurry. This investigation enabled the development of a comprehensive AA performance evaluation. Hydrate agglomeration was detected and quantified by simultaneous increases in the relative motor current and chord length distribution.

As oil and gas industry strive for better gas hydrate management methods, there is the need for better understanding of hydrate formation and plugging tendency in a multiphase flow. In this work, an industrial-scale high pressure flowloop was used to investigate gas hydrate formation and hydrate slurry conditions at different flow conditions; fully dispersed and partially dispersed systems. It has been shown that hydrate formation in partially dispersed system can be more problematic as compared to fully dispersed system. For hydrate formation in partially dispersed system, it was observed that there is rapid hydrate growth and rapid increase in pressure drop upon hydrate formation. This is in-contrast to fully dispersed system in which there is gradual increase in the pressure drop of the system. Further, for partially dispersed system, studies have shown that there is hydrate film growth at the pipe wall. This film growth increases the probability of hydrate particle agglomeration and bedding phenomenon, which that lead to flowline plugging. As there is different hydrate formation and plugging mechanism for fully and partially dispersed system, it is thus necessary to investigate and compare systematically the mechanism for both systems. In this project, all experiments were specifically designed to mimic the flow systems that can be found in actual oil and gas pipelines (full and partial dispersion) and understand the transportability of hydrate particles in both systems. Two variables were investigated in this work; amount of water (water cut, WC) and pump speed (fluid mixture velocity). Three different water cuts were investigated; 30, 50 and 90 vol.% water cut. Similarly, three different pump speeds were investigated; 0.91, 1.89, 2.99 m/s. The results from these meausrements were analyzed in terms of relative pressure drop (?P rel ) and hydrate volume fraction (f hyd ). It was observed that for all water cuts investigated in this work, the ?P rel decreases with increasing pump speed, at a similar hydrate volume fraction. Flowloop plugging occurred for tests with 50 vol.% water cut and pump speeds lower than 1.89 m/s, and for tests with 90 vol.% water cut at a pump speed of 0.91 m/s. Additionally, in all 90 vol.% water cut tests, emulsion breaking where the two phases (oil and aqueous water) separated was observed upon hydrate formation.

This paper describes the measurement and modeling of turbidity currents (TC) in the Congo Canyon and the application of that data to design of a telecommunications cable. There are few direct measurements of TCs largely because the measurement instruments are often damaged. Indeed, this is only the second set of measurements ever recorded in the Congo Canyon, and the only set that shows the propagation of TCs through multiple sites. Four moorings were deployed in 2013 along a 500 km stretch of the Canyon and measured roughly a dozen TCs during a 5-month period. The largest event reached 150 cm/s. Two-D and 3-D numerical models were set up and calibrated using the measurements. The 3-D model shows significant along- and cross-channel variations and these results were used to select optimal crossing locations. The models were then integrated with cable data to permit stress and fatigue analysis at selected cable installation locations, permitting both cable route and cable type to be evaluated.