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Collaborating Authors
Vanvik, T.
Abstract The Tanzania Gas Project aims to exploit reserves located offshore from Tanzania in East Africa. The project faces challenges in the management of liquid content due to deep waters, rough seabed terrain, long transport lines to shore, relatively steep inclinations, and very dry reservoir fluids. The narrow operational envelope associated with the water depth underlines the importance of accurate flow simulations for design and production. In addition, the low liquid loading conditions are expected to result in substantial liquid accumulation in the upwardly inclined sections of the pipeline for low production rates. A large-scale experimental campaign was launched to reduce the uncertainty in the field development. A novel experimental "screening technique", allowed for the sampling of an unprecedented number of flow rate combinations corresponding to the onset of liquid accumulation. Diameter scaling was addressed by conducting similar experiments in 8- and 12-in. pipes. Froude number similarity was utilized for scale-up and to assess model predictions for field conditions. The data confirmed That the flow model captures the correct physics, and allowed for fine tuning. The updated model was applied in an uncertainty analysis for the Tanzania field, based on a large number of combinations of key input and flow model parameters, sampled from estimated uncertainty distributions. Simulation results for gas production rate, minimum turndown point, etc. were determined as probability distributions. The effort to quantify and reduce uncertainty has been very successful. Engagement of the operating company with experimental researchers, model developers, and software suppliers greatly increased the understanding of the physics and diameter scaling of low liquid loading flows, significantly reducing the uncertainty for gas condensate field developments.
- Africa > Tanzania (1.00)
- North America > United States > Texas (0.28)
Abstract We have analysed a set of special large scale experiments run at SINTEF designed to characterize liquid accumulation in gas condensate pipelines at low liquid loads. The goal of the analysis was to clarify what the experiments actually measured: The critical point, where the two-phase Froude number equals unity, or the so-called accumulation point, where the liquid holdup starts to increase sharply with reducing gas flow rate. We developed an algorithm for computing the two points and performed a study to quantify the deviations between liquid flow rate and holdup at the critical point and at the accumulation point. We have found that the experiments give the accumulation point when the critical holdup is lower than the holdup at the accumulation point, which is normally the case in the current campaign. For steeper pipe inclinations, however, it is possible that the critical holdup is higher than the holdup at the accumulation point. In this case, experiments would be expected to measure the critical point. Introduction An extensive experimental campaign was run in 2013 at the SINTEF Multiphase Flow Laboratory at Tiller, Kjølaas and Holm (1). The objectives of the campaign were to localize the onset of liquid accumulation for decreasing gas flow rate in two-phase low-liquid-loading flows for various pipe diameters, pipe angles and liquid rates (USL), to measure the extent of the regions where multiple holdup solutions exist and to measure the associated liquid holdups. In the main type of experiments, from now on referred to as screening experiments, the test section was filled about half full of liquid. Then the liquid inflow was stopped and a gas flow rate inside the region of multiple holdup solutions was set, transporting the liquid out of the pipe at a low flow rate. A controlled injection of liquid at the inlet was used to keep the liquid level gradient in the middle of the pipe. The liquid holdup was then logged at several locations along the test section, and the liquid outflow was measured using a collecting tank with a level measurement system. An overview of the experimental setup is shown in figure 1. The initial idea with the experiment was that when three holdup solutions exist at the actual conditions, the high holdup region in the lower half of the pipe represented the high holdup solution and the low holdup region in the upper half of the pipe represented the middle or the low holdup solution. The liquid outflow was interpreted as the "accumulation point" or liquid holdup take-off point at the set inclination angle and gas flow rate, i.e. the liquid flow rate at the jump from low to high holdup.
- South America > Paraguay > Olga-1 Well (0.89)
- Europe > Norway > Barents Sea > Olga Basin (0.89)
Validation of OLGA HD Against Transient and Pseudotransient Experiments from the SINTEF Large Diameter High Pressure Flow-Loop
Staff, G. (Schlumberger) | Biberg, D. (Schlumberger) | Vanvik, T. (Schlumberger) | Hoyer, N. (Schlumberger) | Nossen, J. (Institute for Energy Technology) | Holm, H. (Statoil) | Johansson, P. S. (Statoil)
Abstract In this paper we have compared the OLGA HD stratified flow model against transient ramp-up and pseudo transient experiments from a Statoil funded experimental campaign performed at the SINTEF Multiphase Flow Laboratory. The experiments were designed to specifically target the transition point from low to high liquid holdup; the accumulation point. We have explained how the removal of the liquid, when the gas flow is increased to inside the multiple holdup solution region, can be described by a steady state fully developed flow approximation. OLGA HD showed excellent predictions compared to the accumulation point experiments. We have also compared the time needed to remove the liquid for a fully transient simulation of experiments with ramp-up into the multiple holdup solution region. A retuned version of OLGA HD, presented in [1], performed well also on the experiments where OLGA 2014.1 HD overpredicted the time needed to remove the liquid. Introduction Multiphase flow simulations of gas-condensate pipeline transport are a challenging task. Important properties are the pressure drop for high rates and liquid accumulation at low rates; factors contributing to determining the operational envelope of the field. However, not only the liquid content and pressure drop at steady operating conditions are important but also behaviour during transient operations like rate changes and outlet pressure changes. The arrival time and the rate of the liquid after ramp-up may be critical factors when designing liquid receiving facilities and operational guidelines. The work described in this paper originates from a project funded by Statoil where the uncertainty of OLGA for a gas-condensate field offshore Tanzania has been evaluated. The Tanzania project is described in more details in [2]. The project consists of two parts: the "Large Scale Liquid Loading Two-phase Flow Tests" campaign carried out at the SINTEF Tiller large scale test facility, and the "Core Model Evaluation and Flow Assurance Risk Study" done by Schlumberger. The experiments are described in more detail in [3]. The OLGA HD stratified flow model is the next generation flow model for stratified flows, the predominant flow regime in a gas condensate pipeline. In this paper we will validate the OLGA HD 2014.1 flow model against some of the transient and pseudotransient experiments done in the Large Scale Liquid Loading Two-phase Flow Tests campaign.
ABSTRACT In every oil and gas field development projects, especially when moving into deep water and/or long tieback distances in harsh environments, flow assurance is of crucial importance in order to define a robust, reliable concept which will ensure security of supply during the whole production phase. There are, however, several parameters which affect the flow assurance. The value of these parameters usually is associated with uncertainty, especially in the early phase of the project, as in the concept definition/ concept selection phase, and this will inevitably bring uncertainty into the flow assurance analysis. Understanding the level of uncertainty and impact on production performance is the key to making sound technical decisions. An important aspect when moving to ultra long distances is that the effect of small relative uncertainties scaled with 500 km may potentially accumulate to large absolute errors. This paper, which is the first out of two papers in serie /2/ describe a method which has been developed by Shtokman Development AG together with SPT Group in order to facilitate a systematic way of analysing the risk picture, and to identify the major risk contributors in a general flow assurance project. The work and the approach presented is a continuation and improvement of the approach presented in /1/. Application of the method on the ultra long 550 km two-phase flow trunkline from the Shtokman Field to shore is illustrated.
ABSTRACT In every oil and gas field development project, especially when moving into deep water and/or long tieback distances in harsh environments, flow assurance is of crucial importance in order to define a robust, reliable development concept which will ensure security of supply during the whole production phase. There are, however, several parameters which affect flow assurance. The value of these parameters is usually associated with uncertainty, especially in the early phase of the project, as in the concept definition/concept selection phase, and this will inevitably bring uncertainty into the flow assurance analysis. This paper, together with ref (2), describes a methodology which has been developed by Shtokman Development AG in conjunction with SPT Group in order to facilitate a systematic way of studying the risk picture and identifying the major risk contributors in a general flow assurance project. Application of the method on the ultra-long 550 km two-phase flow trunk line from the Shtokman Field to shore is illustrated.