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Collaborating Authors
Well & Reservoir Surveillance and Monitoring
The gas flowing from the gas reservoir to the pipeline is often accompanied by condensate and by water. If the gas flowrate is relatively low, this liquid may stay in the pipeline and form liquid pools in the low elbows. These liquid pools can create various problems for oil and gas production: they increase the pressure drop, increase the risk of creating hydrates and corrosion, and they can introduce a production instability in the form of long terrain slugs when the gas velocity is increased and the liquids are swept out of the dip. As shown in Figure 1a, a low elbow with a pool of liquid and gas flowing over it represents a unique type of two-phase flow: zero net liquid flow (ZNLF). Although two phases are present, only the gas is transported through the V-section, while the liquid remains in the elbow, moving upward into the downstream leg - either in the form of slugs, or as a layer, depending on the amount of liquid in the dip and the gas velocity - driven by the shear stress exerted by the gas on the gas/liquid interface.
- Europe (0.46)
- North America > United States > Gulf of Mexico > Eastern GOM (0.25)
- Reservoir Description and Dynamics (1.00)
- Production and Well Operations > Well & Reservoir Surveillance and Monitoring > Production logging (0.97)
Two-Phase Flow Splitting Experiments in an Impacting Tee With Two Risers
van der Gronden, W.R. (Delft University of Technology) | Haandrikman, G. (Shell Projects & Technology) | T'Joen, C.G.A. (Shell Projects & Technology) | Henkes, R.A.W.M. (Delft University of Technology and Shell Projects & Technology)
Abstract We have carried out laboratory experiments for the flow split of a gas-liquid flow from a single flowline to a dual riser. The facility used for the experiments is the air-water loop at the Shell Technology Centre in Amsterdam. The 2" diameter loop consists of a 100 m long flowline followed by a dual 15 m high vertical section. The two risers are connected to the same separator at a platform that is operated at atmospheric pressure. This study is an extension of our previous experiments that were carried out for a non-symmetric splitter (i.e. branching tee) at the riser base, whereas the current experiments use a symmetric splitter (i.e. impacting tee) at the riser base. The results showed that even though the riser base splitter was symmetric, the flow split was not fully symmetric. The splitting could be controlled by either partly closing the top valves at the riser top or the two valves at the riser base. At low flow rates one riser was filled with a liquid column and all production went through the other riser. Choking the valves at relatively low flow rates gave hysteresis, which disappeared at increased gas flow rate. The gas flow split could be controlled with the valves. For the liquid flow rates tested there was a strong tendency for the liquid to split more or less evenly over the two risers, almost irrespectively of the back pressure imposed by the valve choking.
- Production and Well Operations > Well & Reservoir Surveillance and Monitoring > Production logging (1.00)
- Facilities Design, Construction and Operation > Pipelines, Flowlines and Risers > Risers (1.00)
Abstract The gas drift velocity in an elongated bubble can be measured as the bubble velocity moving through stagnant liquid in a pipe. In this study, Computational Fluid Dynamics (CFD) is used to numerically simulate the motion of elongated gas bubbles into liquidfilled channels and pipes. The steady, inviscid flow CFD solution agrees with the analytical solution. Furthermore, the CFD solution for viscous flow agrees with new experimental data. Two flow regimes were predicted by the viscous flow simulations: one of constant bubble velocity and another with decreasing bubble velocity over time. A change in flow regime is observed both in terms of the bubble shape and the gas drift velocity. Correlations are derived from the CFD results that describe the time dependent drift velocity as a function of the liquid viscosity.
- Reservoir Description and Dynamics > Reservoir Fluid Dynamics (1.00)
- Production and Well Operations > Well & Reservoir Surveillance and Monitoring > Production logging (1.00)
- Reservoir Description and Dynamics > Reservoir Simulation (0.95)
Particle Image Velocimetry Measurements in Stratified Air/Water Flow in a Horizontal Pipe
Birvalski, M. (Delft University of Techonology) | Tummers, M.J. (Delft University of Techonology) | Delfos, R. (Delft University of Techonology) | Henkes, R.A.W.M. (Delft University of Techonology and Shell Projects & Techonology)
ABSTRACT This paper reports on an experiment aimed at obtaining detailed velocity fields in a wavy liquid layer in stratified air/water pipe flow. By combining Particle Image Velocimetry (PIV) with an interface detection technique, the velocity field is resolved from the pipe wall to the interface. Furthermore, since the shape of the interface is resolved at each time instance, this information is used in a phase-averaging procedure, which provides the phase-resolved velocity profiles. These profiles are then used to separate the wave-induced motion from the turbulence-induced motion in the liquid layer. In this way, two different wavy regimes (one laminar and one turbulent) are analysed. The results of the measurements are compared to theory of waves and turbulence.
- Production and Well Operations > Well & Reservoir Surveillance and Monitoring > Production logging (1.00)
- Reservoir Description and Dynamics > Reservoir Characterization (0.91)
ABSTRACT We have carried out laboratory experiments for the phase split of a gas-liquid flow from a single flowline to a dual riser. The facility used for the experiments is the air-water loop at the Shell Technology Centre in Amsterdam. The 2" diameter loop consists of a 100 m long flowline followed by a dual 15 m high vertical section. The two risers are connected to the same separator at a platform that is operated at atmospheric pressure. The set-up includes a non-symmetric side-branch T-splitter, of which both the side arm and the run arm result in a vertical riser (Riser 1 and Riser 2, respectively). All experiments were conducted with slug flow conditions in the incoming flowline. It has been observed in the experiments that the liquid phase preferentially flows into Riser 2, while the gas phase is predominantly diverted through Riser 1. However, due to the vertical orientation of the risers, this maldistribution can result in gravity dominated flow in Riser 2. As a result, quasi-stable modes form in the dual riser system. These can imply extreme situations, like a fully liquid-filled Riser 2 or partial separation of the phases over the two risers. Each mode has a typical riser base pressure. It was observed that manual choking can influence the phase split (albeit to a limited extent), and is capable of switching the system between the quasi-stable modes. For specific combinations of valve openings and flow rates, Riser 2 experiences a severe slugging cycle. As a result, the phase split shows strong transient behaviour, either with constant cycle times or with an irregular time dependence. Also here manual choking can influence the characteristics of the cycle and is capable of completely suppressing it.
- Production and Well Operations > Well & Reservoir Surveillance and Monitoring > Production logging (1.00)
- Facilities Design, Construction and Operation > Pipelines, Flowlines and Risers > Risers (1.00)
ABSTRACT: At constant inflow conditions, large-amplitude pressure and flow rate fluctuations may occur in a pipeline-riser system operating at relatively low liquid and gas flow rates. This periodic flow instability has been referred to as severe slugging. In this experimental study, three different orientation angles of the pipeline upstream of the riser base were investigated. The experiments were carried out in a downward inclined pipeline, in a horizontal pipeline and in a hilly-terrain pipeline followed by a vertical riser. Air and water were used as the experimental fluids. For each pipeline-riser configuration, different types of flow instability were found. 1 INTRODUCTION Pipeline-riser configurations in an offshore oil and gas production facility are required to transport multiphase hydrocarbons from a subsurface oil and gas reservoir to a central production platform. The diameter of the pipeline and the riser ranges from typically 0.1 to 0.8 m. The length of the pipeline can vary from a few kilometres to more than hundred kilometres. The height of the riser depends on the water depth, which can be more than two kilometres (in deepwater areas). At relatively low flow rates, liquid accumulates at the bottom of the riser, creating a blockage for the gas, until sufficient upstream pressure has been built up to flush the liquid slug out of the riser. After this liquid surge, and subsequent gas surge, part of the liquid in the riser falls back to the riser base to create a new blockage. This transient cyclic phenomenon is called severe slugging. Severe slugging can significantly reduce the production from the reservoir (due to an increased back pressure) and also can damage or even lead to a shut down of the platform facilities, downstream of the riser, like separators, pumps, and compressors.
- Production and Well Operations > Well & Reservoir Surveillance and Monitoring > Production logging (1.00)
- Facilities Design, Construction and Operation > Pipelines, Flowlines and Risers > Risers (1.00)
ABSTRACT: A Lagrangian three-phase slug tracking model is demonstrated for a severe slugging case with gas, oil and water in an S-shaped riser. The model is an extension of a hybrid twophase flow scheme in which a two-fluid model formulation is used in the stratified flow region. In the slug body region, an incompressible flow model is applied. Mass and momentum conservation equations are solved for open and moving control volumes. This moving grid formulation allows for tracking of discontinuities within the flow, without numerical diffusion. A sub-grid two-fluid model in the bubble region allows for slug initiation directly from the two-fluid model in combination with a fine grid. Alternatively, a mechanistic slug initiation model may be used in combination with a coarse grid. The model is presented and applied to a severe slugging case in which oilwater separation occurs during slug build-up. The third phase is modeled with a mass conservation equation and an oil/water slip model in a mixture liquid momentum equation formulation. 1 INTRODUCTION The introduction of nuclear power generation in the mid 1950s increased the need for accurate and reliable methods to predict two-phase steam and water flows in pipe networks. This led to the development of several commercial codes for one-dimensional two-phase pipe simulation. Almost two decades later, a new field of application of the multiphase technology arose with the emergence of oil and gas production from deep water offshore fields. Several codes specifically designed for such systems were developed. These tools were to a large extent based on the modelling and simulation principles originally introduced with the nuclear technology, and were mainly suited for simulation of two-phase oil and gas flows. Here, an algebraic slip model for the relative velocity between the oil and the water was utilized.
- Reservoir Description and Dynamics > Reservoir Simulation (1.00)
- Reservoir Description and Dynamics > Fluid Characterization > Fluid modeling, equations of state (1.00)
- Production and Well Operations > Well & Reservoir Surveillance and Monitoring > Production logging (1.00)
- Facilities Design, Construction and Operation > Pipelines, Flowlines and Risers > Pipeline transient behavior (1.00)
Experiments for air-water flow with and without added foamers were performed in a 50 mm diameter 12 m long vertical pipe at ambient pressure. It was observed that adding foamers to water will lead to a lower pressure drop at superficial gas velocities below the transition limit from annular flow to churn annular flow (which is around 15 m/s) and at superficial liquid velocities between 0.5 and 2 cm/s. Visualisation of the flow with a high speed camera indicates that the decrease in the pressure drop is due to the more regular nature of the flow when the water is foaming: churning of the flow is suppressed by the foam. This is confirmed by the decrease of the pressure oscillations in the presence of foamers. These experiments give insight into why and how liquid loading in gas wells is prevented by the addition of foamers. 1 INTRODUCTION In a gas well, both liquids – in the form of water and gas condensate – and gas are produced. If the reservoir pressure is high, the gas velocity in the well tubing is sufficient to drag the liquids to the surface. However, near the end of field life when the reservoir pressure has depleted, the gas velocity becomes too low to transport the liquids through the well. The minimum gas velocity required to lift the liquids is called the criticalvelocity. When the gas velocity becomes lower than the critical velocity, liquid will start accumulating at the bottom of the well. This will generate a large hydrostatic pressure in the well, which severely limits the gas production. This process is called liquid loading (1). Most foamers used in gas wells foam only the water (2), but there also exist some condensate foamers (3). In this work, only a water-based foamer has been considered.
- Reservoir Description and Dynamics (1.00)
- Production and Well Operations > Well & Reservoir Surveillance and Monitoring (1.00)
- Production and Well Operations > Artificial Lift Systems > Gas well deliquification (1.00)
By-pass pigging, as compared to normal pigging, reduces the pig-generated liquid slug. CFD (Computational Fluid Dynamics) was applied to understand the flow in and around the by-pass pig under both single phase and multiphase flow conditions. This can help to optimize the velocity of the pig and to define the proper operating envelop, that prevents that the pig gets stuck in the pipeline. Three levels of modeling have been investigated, namely: analytical (i.e. single point multiphase flow correlations), 1D (i.e. using the dynamic pipeline simulator OLGA) and 2D/3D CFD (using Fluent). In the CFD analysis a 2D axis-symmetric model for the single phase flow through the by-pass area is created. Furthermore, CFD simulations were carried out for the multiphase flow in a 2D channel to investigate the mechanism of the reduction in pig-generated volume. The multiphase flow results show four zones in which the flow downstream of the pig can be classified. 1. INTRODUCTION Offshore gas-condensate trunklines normally end in a large onshore slugcatcher. This slugcatcher can be as large as 5000 m3, and is meant to both separate the gas and condensate (and water) and to temporarily store liquid slugs. New projects (with longer pipeline lengths and with larger pipe diameters) can require even larger slugcatchers (e.g. 8000 to 10000 m3). The presence of a large slugcatcher will guarantee the continuous supply of gas to the downstream gas plant. The available literature on by-pass pigging is limited. Out [1] solved the problem of a slug of liquid between two sealing pigs in an isothermal 1-D flow field by using a standard numerical scheme with equally expanded grid intervals behind the pig. Minami and Shoham [2] used a mixed Eulerian-Lagrangian approach in the solution of the transient two-phase gas/slug system.
- Europe (0.68)
- North America > United States (0.28)
- Research Report > New Finding (0.48)
- Research Report > Experimental Study (0.34)
- Reservoir Description and Dynamics > Reservoir Fluid Dynamics > Multiphase flow (1.00)
- Production and Well Operations > Well & Reservoir Surveillance and Monitoring > Production logging (1.00)
- Facilities Design, Construction and Operation > Pipelines, Flowlines and Risers (1.00)
- Facilities Design, Construction and Operation > Facilities Operations > Pipeline pigging (1.00)
In this study, the occurrence of multiple solutions in stratified flows was investigated. The model equations give multiple holdup solutions for certain flow regimes – in small angle upflows with low liquid velocity (low liquid loading) and with low to moderate gas velocity. We applied a steady state as well as a transient flow model, supplied with different closures, verifying the structural stability of different solutions. We compared our model results to observations in our own experiments for zero net liquid flow, and also with two experimental cases by other authors, who investigated the occurrence of hysteresis or holdup discontinuities in stratified flows. 1 INTRODUCTION Long gas/condensate pipelines follow the natural terrain and thus have an undulating profile. Since they operate in the low liquid loading regime, the flow pattern is predominantly stratified flow. In those parts of the pipeline which are slightly upwardly inclined, a steep change in holdup can be observed when the gas velocity is decreased. Under these same conditions, the standard stratified two-phase flow models predict the occurrence of multiple holdup solutions. It is our goal to investigate if we can reliably predict which holdup solution is going to happen in reality, and at which conditions the sudden change in holdup will take place. One of the first studies to point out the occurrence of multiple solutions under certain conditions in the original two-phase stratified flow model presented by Taitel and Dukler (1) was done by Baker and Gravestock (2). Landman (3, 4) and Ullmann et al. (5) showed that this was also the case when laminar gas/liquid flow in rectangular ducts was solved exactly. Further, Landman (3, 4) parameterized the multi-valued solutions, and did a stability analysis and dynamic simulations in order to see which of the solutions is likely to happen in reality.
- Reservoir Description and Dynamics (1.00)
- Production and Well Operations > Well & Reservoir Surveillance and Monitoring > Production logging (1.00)