Mass conservation around pipeline joints has been used to derive directed graphs to model pipeline networks  but has not been used to model the mass flow distribution in co-current, steady state, gas-liquid flow patterns occurring in individual pipe segments. Steady state momentum conservation applied to a macroscopic control volume of flowing gas-liquid can result in a one dimensional force balance along the pipe axis. Achieving a consistent set of rules for graphically representing the way mass and momentum is conserved for all known flow patterns, regardless of their internal macroscopic structures can help visualize the way nature distributes mass and energy when gas and liquid flow through a pipe.
Gainville, M. (IFP Energies Nouvelles) | Cassar, C. (IFP Energies Nouvelles) | Sinquin, A. (IFP Energies Nouvelles) | Tzotzi, Ch. (Technip) | Parenteau, T. (Technip) | Turner, D. (ExxonMobil Development Company) | Greaves, D. (ExxonMobil Development Company) | Bass, R. (ExxonMobil Development Company) | Decrin, M-K. (Total E&P) | Glenat, P. (Total E&P) | Gerard, Fl. (Total E&P) | Morgan, J.E.P. (Woodside Energy Limited) | Zakarian, E. (Woodside Energy Limited)
Gérard Total E&P, France J E P Morgan, E Zakarian Woodside Energy Limited, Australia There are many ways to prevent hydrate formation in production flowline and riser systems. Recently, actively heated pipelines are being considered for hydrate plug prevention, whereby heating is applied to maintain the production fluid operating temperature above the hydrate formation temperature either continuously during normal production, or intermittently during shutdown and restart periods. However, the transition from maintaining a minimum temperature in the production system to hydrate plug dissociation by using active heating is a change requiring qualification prior to operator implementation. The purpose of the work described here is to validate the use of active heated pipelines for safe hydrate plug dissociation. Technip France has conducted a series of hydrate plug dissociation tests in a full scale electrically trace heated pipe in pipe prototype (ETH-PiP) at the IFPEN facilities at Lyon, in collaboration with Total E&P, ExxonMobil Development Company and Woodside Energy Limited. The design and the characteristics of the ETH-PiP are identical with the ETH-PiP installed for Total UK at the Islay field.
It is believed that most of the new discoveries of oil and gas are thought to occur offshore into deeper water, which intrinsically pose a collection of flow assurance and reservoir management difficulties. Offshore the multiphase mixture is transported to the surface in a pipeline riser system, see Fig 1, and one of the major challenges is delivering the fluid up the riser in the most viable manner to the surface facilities. Flow assurance activity is gaining more recognition in the oil and gas industry as a tool for ensuring the constant economic production from wells. There are potentially numerous phenomena that can be detrimental to flow assurance, such as hydrates, waxes, severe slugging (SS) and asphaltenes; just to name a few.
This paper discusses the effect of drag reducing polymers on the Tubing Performance Curve (TPC) of vertical air-water flows at near atmospheric conditions. The effect of polymer concentration, liquid and gas flow rates on the pressure drop curve (Tubing Performance Curve) was investigated experimentally. The results showed that polymers tend to reduce the interfacial roughness, which is counter productive in most cases as it increases the range where gravity dominates the flow. However, at higher gas rates, experiments suggest that lower the wall-liquid shear stress translates into a decrease in the pressure drop, making the use of polymers beneficial to extract early gas at a faster rate. These results can be explained by an analytical model. The derived understanding of the effect of polymers on 2-phase flows can be generalized to other flow regimes and holds promises as a valuable way to address other multiphase production issues.
Since the start of commercial applications of multiphase pumps, their installations have increased steadily. Today a number of reputable manufacturers offer a widespread pump range in regard to flow rate and pressure building capability. However, the foremost working principle still is the twin-screw technology.
Twin-screw pumps depend on liquid availability to seal the internal clearances and remove compression and friction heat generated. Different technical solutions to overcome this issue are available. Separation, storage and recirculation of produced liquid are a common way for this. However, pumps installed in parallel require special attention in regard to upstream flow splitting. This is especially true for multiphase pumps being fed by wells which are far away, as long gas slugs have to be envisaged.
The operation of multiphase pumps requires observing up- and downstream flow scenarios, as well as detailed knowledge of the entire (pumping) process. Furthermore potential solids production has to be taken into account.
This paper presents experimental results of viscous oil-water flow obtained from different facilities. These facilities have different length scale (length and pipe diameter), and both model oil and crude oil were used in the tests. The detailed analysis of these data covers: flow regime behaviour, emulsion viscosity, wall and interfacial shear stress for a stratified flow, etc. An assessment of the performance of the classical models of oil-water flow is conducted.
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)
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.
The dominant form of production is multiphase and when the flow regime is stratified or stratified-wavy it brings the risk of TOLC. Since the 1990's a significant number of instances of this form of corrosion have been detected in subsea pipelines requiring expensive mitigation. Typically, the corrosion mechanism had not been considered significant during design and hence the integrity of the pipeline was at risk due to higher than expected corrosion rates (1, 2, 3). Once TOLC occurs, it becomes an expensive problem to fix. The only remedy with a track record is batch or slug inhibition. Unfortunately, during such batch operations, production has to be lowered/ stopped and the mitigation process will need to continue for the rest of the production life, causing a major impact on the OPerating EXpenditure (OPEX). This paper: discusses how TOLC occurs; reviews the available mitigation methods used in design; and shows by examples that using flow assurance models in the design phase can allow a cost effective solution to be found that meets the system-level design requirements. The present paper leverages lessons learned from previous INTECSEA project design work and discusses ways to properly understand and mitigate TOLC in the early design stages of a project.
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.
Soepyan, F.B. (The University of Tulsa) | Cremaschi, S. (The University of Tulsa) | Sarica, C. (The University of Tulsa) | Gao, H. (Chevron Energy Technology Company) | Subramani, H.J. (Chevron Energy Technology Company) | Kouba, G.E. (Chevron Energy Technology Company)
Transport of solids produced with oil and gas is desired to avoid flow assurance problems. Stratified flow is a challenging flow regime for solids transport because the solids are trapped in the relatively slow-moving liquid film. Our analysis revealed discrepancies between predictions of existing multiphase models and experimental observations. Thus, we extended single-phase models to stratified flow, assuming solids transport in the liquid phase, by evaluating the input characteristic length scales. We considered four length scales, and compared the models' predictions with experimental observations. The models' predictions are most accurate when the liquid film height is used as input.