An integrated framework for model-based flow assurance in deep-water oil and gas production




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НазваниеAn integrated framework for model-based flow assurance in deep-water oil and gas production
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18th European Symposium on Computer Aided Process Engineering – ESCAPE 18

Bertrand Braunschweig and Xavier Joulia (Editors)

© 2008 Elsevier B.V./Ltd. All rights reserved.

An integrated framework for model-based flow assurance in deep-water oil and gas production

Eduardo Luna-Ortiz,a Praveen Lawrence,b Constantinos C. Pantelides,a,b

Claire S. Adjiman,a Charles D. Immanuela

aCentre for Process Systems Engineering, Department of Chemical Engineering, Imperial College London, South Kensington Campus, London, SW7 2AZ, UK

bProcess Systems Enterprise Ltd., Bridge Studios, 107a Hammersmith Bridge Rd, London, W6 9DA, UK

Abstract

Flow assurance in deep-water developments has been identified as one of the main technological problems that the oil and gas industry faces today. Extreme conditions such as high pressures and low temperatures promote the formation of gas hydrates that can potentially reduce or completely block the flow path, causing severe financial losses. An integrated framework for model-based flow assurance management is presented. A two-phase flow model describing the thermal-hydraulic dynamics of subsea pipelines is coupled with a hydrate thermodynamic equilibrium calculation module. The model-based flow assurance framework determines whether hydrate formation can occur at every time instant and at every point along the pipe by comparing the hydrate formation equilibrium temperature and the actual pipeline temperature. The injection of hydrate thermodynamic inhibitors (e.g. methanol) is also included in the model. The framework is implemented in a state-of-the-art modelling tool (gPROMS®). In order to demonstrate its capabilities, shut-in and re-start transient production scenarios are evaluated. Our studies illustrate the benefits of a model-based approach in dealing with the complex and multi-faceted problem of flow assurance.


Keywords: deep-water production, flow assurance, gas hydrate, two-phase flow, drift-flux model.

    1. Introduction and Motivation

Strong energy demand and high prices of hydrocarbons are stimulating the oil and gas industry to explore and produce in challenging environments such as offshore deep-water (> 500 m water depth). Developing deep-water fields poses challenges that have transformed the industry dramatically (Ezekwe and Filler, 2005). Complex production systems include the entire flow structure from the wells and subsea multi-phase pipelines and risers to the host facilities and represent an investment of over US$1 billion (Sloan, 2005).

A major technological challenge in deep-water field development is to ensure the continuous flow of hydrocarbons to the host platform or processing site (Mehta et al., 2000) under the extreme ambient conditions such as low seabed temperatures and high hydrostatic pressures, which can promote the formation of solids such gas hydrates that can clog the pipelines. Such blockages are costly because they interrupt production and require expensive corrective action to rehabilitate the flowlines. Hydrates are ice-like crystals that occur when the hydrogen bonds of water form a cage (host molecule) that encloses a small guest molecule (Sloan, 2007). Common guest molecules are light hydrocarbons (C1 through n-C4) and gases such as N2, CO2 and H2S. Low temperatures and elevated pressure conditions influence the hydrate formation.

When the multi-phase fluid produced from a reservoir flows along a subsea pipeline, it cools down, and as a result, hydrate formation may occur. Gas hydrates plugs are most commonly formed during transient scenarios, in particular during a planned or unplanned shut-down of the production system. In a shut-in, the pressure increases highly and the flowline cools down until the temperature reaches that of the seabed so that the system is very likely to enter the hydrate formation region. Then, during start-up (or re-start) and shut-in, it is vital to manipulate the flow so that the thermal-hydraulic conditions at all points are outside the hydrate formation domain at all times.

Flow assurance refers to the combination of fluid phase equilibria information with transient thermal-hydraulic analysis to develop strategies for the avoidance of hydrate formation (Kaczmarski and Lorimer, 2001; Kopps et al., 2007) and it has a direct impact on the design and operability of the system (Macintosh 2000).

Currently, the basic flow assurance philosophy is to keep the subsea pipelines out of the hydrate region during steady-state. Flowlines are insulated to reduce heat losses to the surroundings, and to help the temperature to remain above the hydrate formation temperature. In addition, thermodynamic chemical inhibitors such methanol can be injected. Inhibitors change the phase behaviour of the mixture by moving the locus of hydrate formation to lower temperatures and/or higher pressures, hence extending the hydrate-free domain (Sloan, 2007).

As a result of the multi-faceted and complex nature of hydrate formation, the modelling of the thermal-hydraulic dynamics of the oilfield fluid production system and the evaluation of equilibrium thermodynamic conditions for hydrate formation are essential for flow assurance. We present an integrated framework for flow assurance management. A two-phase flow model describing the transient thermal-hydraulic behaviour of gas & oil pipelines is coupled with a hydrate thermodynamic equilibrium calculation module. The hydrodynamic model is based on the mixture model (Ishii and Hibiki, 2006) that considers the relative motion (drift velocity) between the gas and liquid phases, in combination with a transient energy balance. On the other hand, the hydrate thermodynamic model is based on the van der Waals and Platteuw (1959) theory. This approach allows the user to determine whether hydrate formation can occur at each time instant and at each point along the pipe by comparing the hydrate formation equilibrium temperature and the actual temperature in the pipeline. The effect of an inhibitor is also modelled. In order, to show the capabilities of the framework, relevant transient scenarios are evaluated.

    1. Model-based flow assurance framework

The one-dimensional transient modelling of multi-phase flow in subsea pipelines and risers requires a number of conservation laws and closure equations. In this work, we adopt the mixture model (drift-flux model) for the analysis of the two-phase (liquid and gas) flow (Ishii and Hibiki, 2006). In the drift-flux model, the gas-liquid mixture is considered as a whole rather than two separated phases. The basic assumption is that the dynamics of the mixture can be expressed by a single momentum balance with a constitutive equation that specifies the relative motion between the phases. This assumption is valid when the phases are strongly coupled (e.g. dispersed flows). In addition, we assume that mass transfer between phases is governed by thermodynamic equilibrium.

      1. Mechanistic two-phase flow model

The compositional continuity equations are

(1)

The momentum balance for the mixture is

(2)

The total energy balance for the mixture is

(3)

where L and G denote the liquid and gas phases respectively, nc is the number components, z is the axial dimension, is the mass fraction of component i in the phase k, k is the volumetric fraction of phase k, k is the mass density of phase k, k is the velocity of phase k, P is the pressure, Q are the heat losses to the surroundings, is the inclination of the pipe with respect to the seafloor, w are the frictional pressure losses, E is the total energy including internal, kinetic and potential contributions. An over-bar represents a property of the mixture.

        1. Closure relationship

The hydrodynamic slip equation is given by

(4)

where K is a factor that depends on the concentration and velocity profiles across the pipe section and S is the drift velocity that takes into account buoyancy effects. Several empirical expressions as function of physical and operational parameters exist for K and S in the literature. The correlations from Shi et al. (2005), adopted in this work, are widely accepted in the oil and gas industry and seem to predict accurately the hydrodynamics of disperse flow and counter-courrent flow.


      1. Gas hydrate thermodynamic model

The thermodynamic gas hydrate model is based on the van der Waals and Platteuw theory. The gas-liquid-hydrate phases are considered in equilibrium. It is assumed that all components (water, hydrocarbons and other species including inhibitors) can appear in all 3 phases. The model consists of a material balance, gas-liquid equilibria, liquid-hydrate equilibria, and equations for hydrate mol fractions and cavity occupancies and can be found elsewhere (e.g. Sloan, 2007). For the purpose of this paper, we simply note that the general form of the model can be written, in compact form, as

(5)

where the model inputs are: M, the molar amounts of all components at a given pipe location and time; P, the pressure and H, the molar amount of hydrate. The model outputs are L and G, the molar amounts of the liquid and gas phases respectively, xH , xL and xG, the molar compositions of the hydrate, liquid and gas phases respectively and T*, the hydrate formation temperature. The incipient hydrate formation temperature can be obtained by specifying H=0.



Figure 1: Integrated multiphase pipeline model for dynamic flow assurance.

      1. Integrated flow assurance framework

The multiphase flow model of section 2.1 is coupled with the hydrate formation module of section 2.2 as shown in Figure 1. Given the pressure of the line and overall (mixture) composition at any point z and at any time instant t, as calculated with the multiphase pipeline model, the (incipient) hydrate formation temperature is computed using the thermodynamic hydrate formation model. We then define the hydrate propensity T(z,t) as the difference between the hydrate formation temperature T* and the actual temperature in the flowline, T, calculated using the multiphase flow model. If the propensity is non-negative, then hydrate formation is thermodynamically favoured and hydrate may form. This approach has been implemented in modular form in the state-of-the-art modeling tool gPROMS® (PSE, 2007).

    1. Case-study

The strategy proposed is applied to a case study which demonstrates the complexity of the flow assurance problem, and illustrates the wealth of information that can be gained from a model-based approach. Consider the simple dry gas production system shown in Figure 2. The mixture consists of 11 components, more than 85% mol methane and very little water (gas-liquid ratio >0.95). The long pipe is slightly inclined and the short riser is vertical. Initially, the system operates at steady state and under a hydrate-free regime.



Figure 2: Flowsheet of deep-water gas production system.

      1. Shut-in scenario.

During shutdown of the production system, the choke valve at the topside is closed. We evaluate the dynamic hydrate propensity along the pipe to determine the time at which hydrate may start to form (touch-time). At 10 km from the wellhead, the touch-time is about 24 hr without inhibitor, while an extra 13 hr are gained if methanol (MeOH) is injected in a ratio of 1% w/w (Figure 3). Touch-time varies as a function of location z, due to the complex interactions within the system.



Figure 3: Hydrate formation propensity at 10 km from the wellhead during a shut-in.

      1. Re-start scenario.

Let us consider the shut-in with inhibitor of section 3.1. After a shut-in, the most common action is to re-start the operation. The line is first depressurised by bleeding the riser at the top, and then the valve is opened until the system is brought back to normal operation. As it was shown in section 3.1, the hydrate propensity increases during a shut-in. When the line is depressurised, the propensity decreases because the system is shifted away from hydrate formation domain. As the valve is opened for re-start, Joule-Thomson cooling occurs, and the hydrate propensity increases sharply along the pipe, leading to a maximum in T with respect to time. Following this, as long as hot fluid circulates through the line, the temperature increases and hydrate propensity decreases again, as illustrated in Figure 4. It can be seen that additional MeOH injection may be necessary if a more conservative margin for hydrate propensity is required during re-start.



Figure 4: Maximum hydrate formation propensity in the pipeline during a re-start.

    1. Concluding remarks and future work

We have presented a model-based framework that incorporates a drift-flux model coupled with a thermodynamic hydrate model. The approach can be used to assess the propensity of hydrate formation during transient operation. The model predicts the complex dependence of hydrate formation on location, time and inhibitor concentration. Such a tool can be used to increase the productivity and reliability of deep-water developments, and for the control and optimisation of gas and oil production systems (e.g. optimal re-start policies).

      Acknowledgements

Financial support from the UK DTI under project TP/2/SC/6/1/10244 is acknowledged. Advice from A. Meredith and M. Williams (Schlumberger Cambridge Research Ltd.) and from A. J. Haslam, A. Galindo and G. Jackson (Imperial College London) is also greatly appreciated.

References

Ishii, M. and Hibiki, T., 2006, Thermo-Fluid Dynamics of Two-phase Flow, Springer.

Ezekwe, J. N. and Filler, S. L., 2005, Paper SPE 95066.

Kaczmarski, A. and Lorimer, S., 2001, Paper OTC 13123.

Kopps, R., Venkatesan, R., Creek, J. and Montesi A., 2007, Paper SPE 109670.

Macintosh, N., 2000, Offshore, 60(10).

Mehta, A., Walsh, J. and Lorimer, S., 2000, Ann. NY Acad. Sci., 912, 366-373.

Mokhatab, S., Wilkens, R. and Leontaritis, K., 2007, Energy Sources, Part A, 29, 39-45.

PSE, 2007, gPROMS® ModelBuilder 3.0.3, www.psenterprise.com

Shi, H., Holmes, J., Durlofsky, L., Aziz, K., Diaz, L., Alkaya, B. and Oddie, G., 2005, SPE J., March, 24-33.

Sloan, E. D., 2005, , Fluid Phase Equil., 228-229, 67-74.

Sloan, E. D., 2007, Clathrates Hydrates of Natural Gas, Taylor & Francis.

van der Waals, J. H. and Platteeuw, J. C., 1959, , Adv. Chem. Phys., 2, 2-57.


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