Over ten different slug frequency models/correlations were evaluated against experimental data as a part of this study. The effect of parameters such as pressure and flow development length on slug frequencies were studied and comparisons with model predictions were made. The available slug frequency models have all been developed for smaller diameter pipes. Comparison of model predictions for 6 in. ID pipe with the experimental results has shown that none of the existing slug frequency models could predict the experimental results with even moderate accuracy. The empirical nature of the current slug models is the main reason for their poor performance. This study also shows significant gaps in the existing slug frequency models/correlations, namely:
Slug flow is a very common flow pattern in pipelines and wellbores. It is characterized by an alternating liquid slug and gas bubble configuration. Slug frequency models are used as input parameters in several mechanistic slug flow models, such as Dukler and Hubbard (1975), Taitel and Barnea (1990), Sylvester (1987), Felizola and Shoham (1995), etc . Thus, the use of an accurate slug frequency model can potentially result in better pressure gradient predictions by the aforementioned slug flow models. Prediction of slug frequency is also important from a materials standpoint, as slugging can significantly increase erosion, corrosion, and fatigue in pipelines. In the following section, an overview of the slug frequency models reviewed in this study is presented.
This paper discusses a transient solid-liquid two-phase flow modelling approach that was applied for real-time drilling hydraulic and cuttings transport calculation. The flow patterns are categorized into seven scenarios, and the flow pattern transition criteria are presented. A generalized transient solid transport model is developed to simulate the transient solid-liquid two-phase flow by combining the transient mechanistic models and the flow pattern prediction method.
Hole cleaning or cuttings transport is one of the major challenges in drilling, especially for extended reach drilling (ERD). The physics behind cuttings transport is solid-liquid, two-phase flow in annulus geometries. A closely related research topic is the solid-liquid, two-phase pipe flow. A critical part of the two-phase flow study for both pipe flow and annulus flow is the understanding of the flow patterns. In engineering applications, a common approach for two-phase flow modelling is to predict the flow pattern and then develop mechanistic models to simulate the flow based on the flow patterns. Accurate flow pattern is the fundamental of the mechanistic models. The predictions from the model may be completely wrong if the flow pattern is not correct.
A one-dimensional model able to predict the film distribution around the pipe wall under conditions typical of wet gas flow in near-horizontal pipes is presented. The model is based on the assumption that i) liquid droplets can only be entrained by the gas from the thick liquid layer flowing at pipe bottom and ii) the deposition of smaller droplets is related to an eddy diffusivity mechanism, while larger droplets deposit by gravitational settling mainly on the pipe bottom. The presence of a thin liquid film all around the pipe wall significantly affects the pressure gradient along the pipe. The present model is a new component of MAST (Multiphase flow Analysis and Simulation of Transitions), a transient, 1-D flow simulator developed for advanced flow assurance studies.
Pipeline transportation over long distances of natural gas in presence of a liquid phase is a common practice in the oil industry and can be extremely challenging when major flow assurance issues, such as corrosion or solid formation and deposition on pipe wall, arise. In these applications, at appreciable gas velocity, only part of the liquid flows at the pipe wall, while the gas entrains the remaining liquid in the form of droplets that tend to deposit back onto the wall layer. In a large diameter pipe, the resulting flow pattern is usually classified as stratified-dispersed (SD) flow. In this flow pattern, the critical parameter to be predicted is the flow rate and thickness distribution of the liquid layer flowing at pipe wall. This is because the split of the liquid phase determines the overall liquid hold-up in the pipe and the pressure losses. Besides to the fluid-dynamic issue, a better knowledge of the flow behaviour of the wall layer has many implications in flow assurance studies. In particular, the effectiveness of the inhibitors usually adopted to prevent corrosion depends on the formation of a liquid film around the pipe wall.
Dai, W. (Auburn University) | Cremaschi, S. (Auburn University) | Islam, M. Azhural (The University of Tulsa) | Nukala, R. T. (The University of Tulsa) | Subramani, H. J. (Chevron Energy Technology Company) | Kouba, G. E. (Chevron Energy Technology Company) | Gao, H. (Chevron Energy Technology Company)
Most multiphase flow models are developed and validated using a limited set of experimental data. Even when extensive experimental data are available, they are collected at laboratory conditions and/or test facilities, whose operating ranges and scales do not usually coincide with the field conditions. Therefore, models are routinely used for extrapolations to conditions where experimental data is not available. For example, this is often the case for very remote operations such as deep water applications. In this paper, we present three approaches to quantify experimental data and model prediction uncertainty for multiphase flow applications. We demonstrate these methods using three applications, estimation of experimental data uncertainty of erosion extent measurements, quantification of prediction uncertainty of critical velocity for sand transport, and of liquid entrainment in two-phase flow.
Multiphase flow occurs in many systems encountered in chemical, petroleum, and nuclear industries. Because efficient design and operation of these systems depend on the ability to predict the flow characteristics, several multiphase flow models have been developed. These models are based on mechanistic approaches, which utilize the conservation equations of mass, momentum, and energy along with empirical or semi-mechanistic closure relationships and adjustable parameters. The resulting equations are solved using various numerical methods and algorithms. The inputs to these models include fluid properties such as density, viscosity and surface tension, flow geometry such as diameter and inclination of the pipeline, and operating conditions such as superficial gas and liquid velocities. The outputs may be flow patterns, pressure gradients, liquid hold-up, etc.
Foam assisted lift is a deliquification method in the oil and gas industry, which aims to prevent or postpone countercurrent gas-liquid flow in maturing gas wells or to assist in removing downhole accumulated liquids. The creation of foam reduces the density of the liquid that needs to be transported and postpones the transition from annular to churn flow to lower gas velocities, which improves the upward transport of liquid carried by foam. This paper presents a model predicting the foam flow behavior in annular flow conditions down to the transition from annular to churn flow, with which the onset of liquid loading is computed.
Liquid loading is a well-known problem that occurs when ‘wet’ gas wells approach their end-of-life. Due to depletion of the reservoir, its pressure drops and as a consequence the gas flow rate in the well drops as well. When only dry gas is present in the well, the reduced gas flow rates have no further effect. However, when a liquid phase is present (either production fluids or condensed fluids) the reduced gas flow rates may, at some point, not be effective in transporting the liquids to topside and they will accumulate downhole (liquid loading). The critical velocity, Ucrit, determines the onset of liquid loading.
When a well is loaded, it may still produce at a low metastable rate, produce intermittently or may not produce at all. Foam Assisted Lift (FAL) is one of the possible methods to remove the downhole accumulated liquids (deliquification) and/or improve the production. In order to design a suitable FAL-system, the prediction of foam flow is a prerequisite.
An average reduction of Ucrit by the application of a surfactant is about 50%, refs. (1), (2). This value is based on field experience and taken as a rule of thumb in foamer applications. In this paper, a model is presented that aims to give a more detailed description of the effect of foamers on the flow.
In this paper we discuss the multiple solutions of the three-phase flow model and how they can be related to the oil and water accumulation and removal for a low liquid loading case. Under certain conditions, a ramp-up of the flow rates results in the liquid being removed in three sweeps. The time scales of the three sweeps may be very different, having a huge impact on the liquid removal time. By studying a steady-state fully-developed three-phase model we explain the physics behind the liquid removal process. The validity of this steady-state fully-developed flow approximation has been checked against transient simulations of ramp-up cases using OLGA HD 2015.1. Through a Statoil sponsored experimental campaign at the SINTEF Multiphase Flow Laboratory, several transient and pseudo transient two- and three-phase experiments were performed. We have compared the experimental measurements against OLGA HD 2015.1 and the predictions are very good. The theory presented in this paper explains the liquid removal process seen in the experiments.
Multiphase flow simulation of gas-condensate-water pipeline transport with low liquid loading is a challenging task. Important properties are the pressure drop for high rates and oil/water accumulation at low rates; these factors contribute to determining the operational envelope of the field. However, the oil/water content and pressure drop are important not only at steady operating conditions, but also during transient operations such as rate changes and outlet pressure changes. The arrival time and the flow rate of the oil and water surges following ramp-up may be critical factors when designing liquid receiving and separation facilities and operational guidelines.
In this work, the flow pattern and drop size development of kinetically unstable oil-water dispersions is studied along a horizontal test section. Experiments with tap water and a low viscosity kerosene oil (5.5 mPa s) are conducted in a 7 m long acrylic pipe with 37 mm ID. Dispersed oil flows are actuated for a wide range of phase fractions and relatively low mixture velocities by using a multi-nozzle inlet with 1056 nozzles. High-speed visualisations show that the flow remains fully dispersed downstream the inlet only at high mixture velocities. At low velocities a continuous oil layer forms, while there is an accumulation of dispersed drops at the upper part of the pipe. The drop size evolution is tracked with a conductivity probe and is shown to depend on the spatial configuration of the flow.
While there have been significant improvements over the last century in the understanding of turbulent dispersed flows in pipes, there are still phenomena that cannot be fully described and are only empirically explained. This lack of understanding can have a major impact on the oil and gas industry and a lot of effort is spent on conducting thorough research to produce new experimental data, formulate more accurate models and develop an extensive theoretical background to analyse the flow characteristics. Through the years many researchers [1, 2] have studied turbulent dispersed flows in horizontal pipes. Various techniques have been implemented to acquire information on their hydrodynamics. These techniques are based on the differences of the properties of the two phases, where the differences in conductivity or refractive index are the ones most commonly exploited. Acquiring drop size information in dispersed flows is of crucial importance for their characterization, but can also prove challenging due to the complexity of the structures formed.
In this paper we perform a comprehensive analysis of two- and three-phase large scale experimental data from the SINTEF Multiphase Laboratory on low liquid loading flows. The experimental work was financed by Statoil ("Experiments for low liquid loading with liquid holdup discontinuities in two- and three-phase flows" ), addressing key flow assurance challenges in the gas condensate field development offshore Tanzania . In the present work we use this new data for the purpose of improving the predictions of LedaFlow. In particular, we are interested in predicting the discontinuous onset of liquid accumulation (due to multiple holdup solutions) for large diameter pipes, which is a very important matter for many wet-gas transport systems. We demonstrate that the current data enables calculation of the interfacial friction factor with unprecedented accuracy for a wide range of parameters. This is important because the interfacial friction is the most crucial model in these circumstances, and ordinarily it has also been the most uncertain closure in multiphase flow models. We show that by calibrating the interfacial friction model to this data, LedaFlow is able to predict the onset of liquid accumulation with remarkable accuracy for three different pipe diameters (4", 8" and 12"), indicating that the model has good scaling abilities. Finally, we show that the prevailing LedaFlow-predictions of holdup and pressure drop also become very accurate for these types of conditions.
IntroductionThis paper summarizes the work performed with respect to closure improvements in LedaFlow for low liquid loading conditions in moderately inclined pipes, with particular emphasis on predicting the onset of liquid accumulation. Here, "low liquid loading" is taken to mean low liquid flow rates, typically USL≤0.01 m/s.
An experimental study featuring two phase gas-viscous oil flow was conducted in the NEL multiphase flow loop to assess the homogenisation effectiveness of the blind-t mixing spool that is commonly associated with many multiphase flow meter (MPFM) installations. The variance in phase distribution at the exit of the blind-t is described, alongside the effects of inlet flow structure on mixing performance. The phase area distribution is captured using an electrical capacitance tomography (ECT) system in parallel with a high speed video logger before flow acceleration through a transparent Perspex venturi tube. The results show that the mixing capacity of the blind-t is dependent on the inlet flow pattern and oil viscosity which consequently influences the phase dispersion and slip characteristics through the venturi section.
The oil and gas industry is becoming increasingly reliant on the advantages associated with multiphase processing technologies (1). Traditionally, critical well testing would utilise separation to isolate the individual flow components and replicate conditions required for allocation and fiscal metering. Although this is a well practiced technique, it relies on excessive piping lengths and large separation equipment, such as a gravity separation vessel, that can take over the already limited space on many offshore production platforms. Direct measurement of multiphase flows is much more complex and often comes at the price of a greater theoretical uncertainty. However, it can be argued that the advantages associated with multiphase metering, such as low CAPEX and OPEX costs (as compared to the single phase measurement process) and the ability to capture real-time well performance characteristics outweigh the disadvantage of reduced measurement accuracy (2), especially for subsea applications.
Chung, S. (Seoul National University) | Pereyra, E. (The University of Tulsa) | Sarica, C. (The University of Tulsa) | Soto, G. (Autonomous Metropolitan University Campus Lerma) | Alruhaimani, F. (The University of Tulsa) | Kang, J. (Seoul National University)
There is a recent interest on the production of medium to heavy oils in offshore environments. The use of multiphase pumps located in platforms has been proposed to ensure the transport of the fluids to the shoreline facilities. After the platform, the multiphase flow stream is redirected to the sea floor using a down comer. Thus, the understanding of the viscosity effect in downward vertical flow becomes critical for the system design.
An experimental study on the viscosity effect has been carried out using a 2-in. ID multiphase flow facility. The viscosity of the oil ranged from 122 to 560 mPa s. The superficial gas and liquid velocities varied from 0.3 to 7 m/s and 0.05 to 0.7 m/s, respectively. Flow pattern, pressure gradient and liquid holdup data were acquired and compared with previous air-water experiments. Three different flow patterns have been identified based on visual observations and capacitance sensor readings. Flow pattern, superficial velocities and viscosity effects on pressure gradient and liquid holdup are presented. Finally, comparisons with available mechanistic models and simulators are reported.
IntroductionA large number of experimental and modelling studies on gas-liquid two-phase flow have been carried out owing to its importance in industrial applications. In petroleum industry, relatively few investigations in vertical downward two-phase flow have been reported as compared with horizontal and vertical upward. Downward flow has been traditionally encountered in relatively short length of pipes in offshore production operations. However with the growth of deep-water production, vertical down-comers from platforms to the seafloor may have lengths of several thousand feet. Accordingly, more accurate prediction of pressure drop and liquid holdup over these lengths becomes significantly important.