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Abstract The risk of plugging due to hydrate formation remains one of the most prevailing flow-assurance problems in deep subsea oil and gas operations. Due to potentially severe economic impact of forming a hydrate plug, it is critical to develop hydrate formation models, which predict temporal and spatial hydrate plug formation in flowlines. Hydrate formation and accumulation mechanisms depend on the flow regimes of the system; in turn, hydrate formation can affect the flow regime of fluid flow. Currently, there are no multiphase tools that account for this coupling and interdependence factor of hydrate formation and flow regime. A simple hydrodynamic slug flow model (Danielson, 2011), based on fundamental multiphase flow concepts, coupled with a transient hydrate formation model, is used to study the effect of hydrates in a gas/water system fluid flow. The model includes a hydrate kinetic model, mass and energy balances, and pressure drop components. The validity of the model is tested against data measured in an industrial flowloop (Joshi, 2012). Using this model to simulate hydrate formation in subsea pipelines shows higher hydrate accumulation with increasing water-hydrate slip (L. Zerpa, Rao, Sloan, Koh, & Sum, 2012). Flowline geometry is also considered to predict the slugging and accumulation of hydrates. This hydrodynamic model predicts flow regime transitions among stratified, stratified-wavy, slug, and bubble flow with and without hydrates. Using a specific model for the slip relations between the phases, the model can predict the classical gas-liquid flow regime map and the impact of hydrates as a third, solid phase on such flow regime maps. This contribution shows that a relatively simple model can be useful in the predictions of multiphase flow and in particular how hydrates affect the flow behavior and must be explicitly accounted as a separate phase. Introduction Clathrate hydrates are crystalline solid compounds, formed at low temperatures and high pressures, comprising of water and gas molecules (Sloan & Koh, 2008). Hydrogen bonded water molecules form the " host" cage entrapping the " guest" gas molecules like methane, ethane, hydrogen sulfide, propane etc., which are also prominent components of natural gas. The formation of natural gas hydrates in deep subsea pipelines is one of the most challenging flow assurance problems (Sloan, 2005), involving significant design efforts to prevent the formation of undesirable hydrate plugs. Various hydrate prediction tools allow accurate predictions of the amount of thermodynamic inhibitor (e.g., methanol or monoethylene glycol) required to completely prevent hydrate formation. The oil and gas industry is gradually shifting from prevention towards hydrate management, approaches, where hydrates are allowed to form, but the plugging risk is minimized (Creek, 2012; Sloan, 2005). Models for hydrate formation kinetics coupled with multiphase flow aspects will be helpful during the design and assessment of hydrate management approaches and in estimating hydrate-plugging risk. A hydrate kinetics model was developed for oil-dominated systems based on the conceptual model presented in Figure 1, which represents an approximation to the mechanism of hydrate plug formation divided in four steps: gas bubble and water droplet entrainment in oil; hydrate film growth at the interface of the droplet/bubble; particle packing, agglomeration, bedding, and deposition; plugging. In the oil phase, these hydrate-encrusted water droplets agglomerate into larger hydrate masses (Taylor, 2006), leading to an increase in the slurry viscosity, which can eventually form a plug (Turner, 2005).

Abstract The formation of natural gas hydrates in deep subsea pipelines is one of themost challenging flow assurance problems. The development of a comprehensivehydrate model (CSMHyK), which predicts temporal and spatial hydrate formationand plugging in flowlines of oil-, water- and gas-dominated systems, will havesignificant utility in flow assurance. This empowers the engineer to design andassess oil/gas transport facilities, with a focus on prevention, management orremediation of gas hydrate formation and blockages. In the current work, wepresent improvements to the hydrate aggregation module used for oil-dominatedsystems, based on experimental data, which account for temperature, particle-particle contact time, excess water, and the presence of surfaceactive compounds. Second, we have extended CSMHyK to water- and gas-dominatedsystems, and have developed fundamental models based on flowloop and laboratorydata. In water-dominated systems, we present a new mass transfer-based growthmodel and hydrate plugging criterion, based on fluid velocity. In gas-dominatedsystems, we present a combined heat and mass transfer model for hydrate filmgrowth on pipe walls. These models are applied to a typical well/flowline/risergeometry used in offshore facilities. This model improves our capability topredict hydrate formation and blockages, by considering dynamic aggregationphenomena in oil-dominated systems, flow regime transition in high water cutsystems, and hydrate film growth in gas saturated systems. Introduction Natural gas hydrates form when small guest molecules contact liquid water athigh pressure and low temperature (Sloan and Koh, 2008), which are typicaloperation conditions of subsea pipelines. The formation of natural gas hydratesin deep subsea pipelines is one of the most challenging flow assurance problems(Sloan, 2005), involving significant design efforts to prevent the formation ofundesirable hydrate plugs. It had been recognized that predicting hydrate formation conditions usingthermodynamic calculations (with excellent accuracy) is not sufficient toestimate hydrate plugging risk (Sloan, 2005). Instead, this can be used todesign hydrate avoidance methods (e.g., chemical injection, thermal insulation, active heating, and pressure reduction), keeping the systems out of the hydratestability region (Creek et al., 2011). The offshore oil/gas industry hasprogressed toward using longer tiebacks (Ronalds, 2005) to connect subsea wellswith platforms, rendering hydrate avoidance methods economically unfeasible. The alternative would be to consider hydrate management approaches, wherehydrates are allowed to form, but the plugging risk is low (Creek et al., 2011;Sloan, 2005). Models for hydrate formation kinetics coupled withtransportability models may be helpful during the design and assessment ofhydrate management approaches, providing estimates of the amount of hydratesthat could form and its transportability in specific scenarios, to estimatehydrate plugging risk.

Abstract The paper highlights the importance of developing a comprehensive gas hydrate model in flow assurance for the oil and gas industry. The comprehensive model should account for mechanisms present in different systems of oil/gas production. Since this kind of tool could be seen as complex and difficult to use, the main focus of the paper is to present an example of generation of "best practices" that can address the needs of a general flow assurance community, using a gas hydrate model developed for oil-dominated systems. The example illustrates the restart of an offshore well, using a typical geometry and fluid properties from the Caratinga Field located at Campos Basin, Brazil. Two extreme cases are studied to identify the worse case scenario, one considering a water-in-oil stable emulsion and the other where water is allowed to separate from the continuous oil phase. Then, the restart procedure of the case with higher risk of forming a hydrate plug is optimized to minimize hydrate formation and plugging risk. From the comparison of the two cases studied, it is concluded that systems with free water have a higher risk of plugging with hydrates. The optimization of the restart of a well shows that a slow restart of the well minimizes the formation of hydrates, decreasing the risk of plugging. The main conclusion is that the gas hydrate model can be used as a tool for the generation of "best practices" for gas hydrates in flow assurance. Introduction Flow assurance is a technical discipline of the oil and gas industry that focuses on the design of safe and secure operation techniques for the uninterrupted transport of reservoir fluids from the reservoir to the point of sale. Offshore explorations in deeper and colder waters impose more challenging scenarios to the flow assurance of the produced streams, requiring production facilities with longer subsea tiebacks for the transport of hydrocarbons from the wellhead to production/processing platforms. These facilities may operate at high pressures and low temperatures promoting the formation of gas hydrates, crystalline compounds formed by hydrogen-bonded water molecules in a lattice structure that is stabilized by encapsulating a small guest molecule, like methane or ethane (Sloan and Koh, 2008). One of the most challenging problems in flow assurance is the plugging of pipelines due to rapid formation of gas hydrates compared to other solid deposits (Sloan, 2005). The formation of gas hydrates in an oil-dominated multiphase flow system containing water, oil, and gas, can be described using the conceptual model illustrated in Figure 1, where hydrates form at the interface of water droplets entrained in the continuous oil phase. In the oil phase, these hydrate-encrusted water droplets can agglomerate increasing into larger hydrate masses, leading to an increase in the slurry viscosity, which can eventually form a plug (Turner, 2005).

The EOR method so called alkaline-surfactant-polymer (ASP) flooding has proved to be effective in reducing the oil residual saturation in laboratory experiments and field projects through the reduction of interfacial tension and mobility ratio between oil and water phases.Two issues are critical for a successful ASP flooding project: i) addressing issues related to laboratory design such as chemicals selection and concentrations, in order to obtain an optimal ASP formulation, and ii) establishing an optimal injection scheme for the field scale flooding process, that will maximize a given performance measure (e.g., oil recovery efficiency or displacement efficiency), considering a heterogeneous and multiphase petroleum reservoir. This paper presents an efficient solution approach for the latter issue.The approach is based on the construction of quadratic response surface models (surrogates) of reservoir simulator outputs and three-level D-optimal design of experiments. It allows to effectively and efficiently establish the optimum ASP injection scheme, and was applied to determine the optimal values of injection rates, slug size and initial date for injection of an off-shore ASP pilot project being developed by PDVSA at La Salina Field, LL-03 Miocene reservoir on the eastern coast of Maracaibo Lake, Venezuela. The optimum injection scheme resulted in substantial savings in chemicals used when compared to the laboratory design.

After conventional waterflood processes the residual oil in the reservoir remains as a discontinuous phase in the form of oil drops trapped by capillary forces and is likely to be around 70% of the original oil in place (OOIP). The EOR method so-called alkaline-surfactant-polymer (ASP) flooding has been proved to be effective in reducing the oil residual saturation in laboratory experiments and field projects through reduction of interfacial tension and mobility ratio between oil and water phases.A critical step to make ASP floodings more effective is to find the optimal values of design variables that will maximize a given performance measure (e.g. net present value, cumulative oil recovery) considering a heterogeneous and multiphase petroleum reservoir. Previously reported works using reservoir numerical simulation have been limited to sensitivity analyses at core and field scale levels because the formal optimization problem includes computationally expensive objective function evaluations (field scale numerical simulation).The proposed methodology estimates the optimal values for a set of design variables (slug size and concentration of the chemical agents) to maximize the cumulative oil recovery from a heterogeneous and multiphase petroleum reservoir subject to an ASP flooding. The surrogate-based optimization approach has been shown to be useful in the optimization of computationally expensive simulation-based models in the aerospace, automotive, and oil industries. In this work we have extended this idea along two directions: i) using multiple surrogates for optimization, and ii) incorporating an adaptive weighted average model of the individual surrogates.The proposed approach involves the coupled execution of a global optimization algorithm and fast surrogates (i.e. based on Polynomial Regression, Kriging, and a Weighted Average Model) constructed from field scale numerical simulation data. The global optimization program implement the DIRECT algorithm and the reservoir numerical simulations are conducted using the UTCHEM program from the University of Texas at Austin.The effectiveness and efficiency of the proposed methodology is demonstrated using a well-known field scale case study.

We present the development of a new model to predict hydrate growth and transport in gas-dominant systems, based on experimental observations of hydrate film growth and particle deposition. Incorporated as a user-defined plugin in a transient flow simulator, we present predictions of hydrate blockage formation using this tool for three of eight Tommeliten field trials: (i) depressurized restart; (ii) thermodynamic inhibitor injection failure and; (iii) pressurized restart. Deposition plays a key role in these predictions, and the new model predicts significant hydrate stenosis occurring in the same timescale as blockage formation in the field trials. The mechanism of sloughing, a key precursor to the formation of hydrate plugs, is not incorporated in a transient simulation environment. However, shear stress predictions as a deposit develops may exceed the threshold previously reported in literature to generate a sloughing event. This represents a key way forward in the development of a comprehensive hydrate prediction tool for oil and gas flowlines.

This paper discusses the problems caused by gas hydrates during gas lift operations in deep-water and cold/arctic areas. Hydrate accumulations that plug the pipelines can interrupt normal production schedules and cause economic loss or even generate a safety risk if not properly handled. Low temperature, high pressure and the presence of water are required for hydrate formation in oil and gas production systems. Here we study the effects of produced gas composition on gas hydrate formation. The presence of acid gas and large hydrocarbon gas molecules tend to facilitate hydrate formation. Injection source well candidates for gas lift are screened based on gas composition. Also, methods to detect hydrate formation in the pipeline will be investigated. Finally, best field practice to prevent hydrate plugs during gas lift operation will be recommended.

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.

Summary As the oil-and-gas industries strive for better gas-hydrate-management methods, there is the need for improved understanding of hydrate formation and plugging tendencies in multiphase flow. In this work, an industrial-scale high-pressure flow loop was used to investigate gas-hydrate formation and hydrate-slurry properties at different flow conditions: fully dispersed and partially dispersed systems. It has been shown that hydrate formation in a partially dispersed system can be more problematic compared with that in a fully dispersed system. For hydrate formation in a partially dispersed system, it was observed that there was a significant increase in pressure drop with increasing hydrate-volume fraction. This is in contrast to a fully dispersed system in which there is gradual increase in the pressure drop of the system. Further, for a partially dispersed system, studies have suggested that there may be hydrate-film growth at the pipe wall. This film growth reduces the pipeline diameter, creating a hydrate bed that then leads to flowline plugging. Because there are different hydrate-formation and -plugging mechanisms for fully and partially dispersed systems, it is necessary to investigate and compare systematically the mechanism for both systems. In this work, all experiments were specifically designed to mimic the flow systems that can be found in actual oil-and-gas flowlines (full and partial dispersion) and to 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 WCs were investigated: 30, 50, and 90 vol%. Similarly, three different pump speeds were investigated: 0.9, 1.9, and 3.0 m/s. The results from these measurements were analyzed in terms of relative pressure drop (ΔPrel) and hydrate-volume fraction (ϕhyd). It was observed that, for all WCs investigated in this work, the ΔPrel decreases with increasing pump speed, at a similar hydrate-volume fraction. Analysis conducted with the partially-visual-microscope (PVM) data collected showed that, at constant WC, the hydrate-particle size at the end of the tests decreases as the mixture velocity increases. This indicates that the hydrate-agglomeration phenomenon is more severe at low mixture velocity. Calculations of the average hydrate-growth rate for all tests conducted show that the growth rate is much lower at a mixture velocity of 3.0 m/s. This is attributed to the heat generated by the pump. At a high mixing speed of 3.0 m/s, the pump generated a significant amount of heat that then increased the temperature of the fluid. Consequently, the hydrate-growth rate decreases. It should be stated that this warming effect should not occur in the field. Flow-loop plugging occurred for tests with 50-vol% WC and pump speeds lower than 1.9 m/s, and for tests with 90-vol% WC at a pump speed of 0.9 m/s. In addition, in all 90-vol%-WC tests, emulsion breaking, where the two phases (oil and water) separated, was observed after hydrate formation. From the results and observations obtained from this investigation, proposed mechanisms are given for hydrate plugging at the different flow conditions. These new findings are important to provide qualitative and quantitative understanding of the key phenomena leading to hydrate plugging in oil/gas flowlines.