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- annular flow (1)
- Artificial Intelligence (1)
- artificial lift system (1)
- bhr group 2012 (5)
- border (1)
- buffer tank (1)
- bypass (1)
- bypass area (1)
- CFD (1)
- closure (1)
- concentration (1)
- correlation (1)
- diameter (1)
- downward (1)
- endress hauser (1)
- equation (1)
- experiment (4)
- flow rate (2)
- flow regime (1)
- foamer (1)
- formulation (1)
- gas velocity (2)
- gas Well Deliquification (1)
- holdup (3)
- holdup solution (1)
- hydrodynamic slug (1)
- hysteresis (1)
- initial condition (1)
- interfacial (1)
- lagrangian one-dimensional three-phase (1)
- liquid holdup (1)
- liquid loading (1)
- liquid production (1)
- liquid velocity (1)
- mass flow (1)
- mixture liquid (1)
- mixture velocity (1)
- momentum equation (1)
- Multiphase (1)
- multiple solution (1)
- one-dimensional three-phase slug (1)
- pig velocity (1)
- pipe (2)
- pipeline (2)
- pipeline pigging (1)
- pipeline upstream (1)
- pipeline-riser configuration (1)
- pipeline-riser system (1)
- pressure drop (2)
- pressure drop coefficient (1)
- production control (4)
- production logging (3)
- production monitoring (4)
- Reservoir Surveillance (4)
- reynolds number (1)
- riser (1)
- riser base (1)
- separation (1)
- shear stress (1)
- Simulation (3)
- simulator (1)
- slug (2)
- steady state (1)
- stratified flow (1)
- superficial gas velocity (1)
- superficial liquid velocity (1)
- surfactant (1)
- Taitel (1)
- transient model (1)
- transient simulation (1)
- transition (1)
- two-fluid model (1)
- Upstream Oil & Gas (5)
- water velocity (1)

**File Type**

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

annular flow, artificial lift system, bhr group 2012, concentration, experiment, flow rate, foamer, gas velocity, gas Well Deliquification, holdup, liquid loading, pipe, pressure drop, production control, production logging, production monitoring, Reservoir Surveillance, superficial gas velocity, superficial liquid velocity, surfactant, transition, Upstream Oil & Gas

SPE Disciplines:

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.

bhr group 2012, bypass, bypass area, CFD, correlation, diameter, holdup, liquid velocity, mixture velocity, Multiphase, pig velocity, pipeline pigging, pressure drop, pressure drop coefficient, production control, production monitoring, Reservoir Surveillance, reynolds number, Simulation, Upstream Oil & Gas

Artificial Intelligence, bhr group 2012, border, buffer tank, equation, experiment, formulation, lagrangian one-dimensional three-phase, mixture liquid, momentum equation, one-dimensional three-phase slug, pipe, pipeline, production control, production logging, production monitoring, Reservoir Surveillance, separation, Simulation, simulator, slug, two-fluid model, Upstream Oil & Gas

SPE Disciplines:

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.

bhr group 2012, closure, experiment, gas velocity, holdup, holdup solution, hysteresis, initial condition, interfacial, liquid holdup, multiple solution, production control, production logging, production monitoring, Reservoir Surveillance, shear stress, Simulation, steady state, stratified flow, Taitel, transient model, transient simulation, Upstream Oil & Gas, water velocity

SPE Disciplines:

SPE Disciplines: Facilities Design, Construction and Operation > Pipelines, Flowlines and Risers > Risers (1.00)

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