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This paper studies the artificial lift methods available to deliquify loaded gas hydrate wells. When hydrate dissociates, a high amount of water will be produced. On a molecular basis, the gas-liquid ratio (GRL) is 1:5.75. A new hydrate reservoir classification system is proposed based on its future water production characteristics. In this paper we discuss the source of liquid loading for different reservoir types, required for the design of suitable artificial lift methods for the hydrate reservoir during its overall life. The challenges of artificial lift methods of hydrate wells are also investigated, such as insufficient reservoir energy, low GLR, low surface and borehole temperature, formation of ice and secondary hydrates, and sand production. Proper selection of artificial lift methods is critical to the long-term profitability of gas production from natural gas hydrate accumulations. The feasibility of different methods is the focus of this paper.

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.