Flow assurance deals with all issues that may arise in the flowline and can cause the flow not to happen properly. It deals with issues like slugging, hydrate formation, the flow of waxy fluids, multiphase flow prediction, etc.
Flow assurance studies can be categorized to steady-state studies and transient studies.
Steady-state flow assurance studies help to draw a clear picture of the flowing system. Steady-state studies results help to understand phase behavior, operational limitations, etc.
For example, knowing what happens in turndown operation, winter, and summer conditions, different feed characteristics help to predict the borderlines of a safe operational area.
The steady-state hydraulic model is used to determine pipeline size. The criteria for line sizing is pressure constraints, erosion velocity limits, and flow regime. All steady-state prediction models assume that pressure, temperature, and physical properties of the fluid remains constant with time. But in the real world, they change with time. However, single-phase pipeline sizing by steady-state hydraulic modeling usually leads us to acceptable results.
There are general guidelines for determining pipeline size as follows:
- For oil/gas gathering pipelines from wellhead to processing plants take 1/3 of the difference between wellhead pressure and separator pressure as allowable pressure drop.
- As a rule of thumb, for long gas/condensate pipelines, allow 10-20 psi per mile (0.04-0.08 bar/100m) frictional pressure drop at design rate.
- Allowable velocity for liquid lines is 1-2 m/s and for gas lines is 5-10 m/s. Continuous operation above 4 m/s for liquids and 20 m/s for gases should be avoided.
- In order to avoid corrosive situations, liquid lines containing a separate water phase, should not be operated at too low velocities (below 1 m/s). This is important at turndown flow conditions, especially in the presence of a considerable amount of H2S or CO2.
- According to API RP-14E, the maximum design velocity in the pipeline which is erosion velocity can be calculated from the following formula:
Vmax = C/ sqrt(Pns)
Vmax=maximum mixture velocity, ft/s
Pns=No-slip mixture density, lb/ft3
C=constant, 100 for continuous services, 125 for intermittent services
Phase Equilibrium and physical properties
Accurate prediction of the phase behavior of flowing fluid is essential in predicting operational constraints.
Steady-state simulators generally have two models to predict physical properties. Black Oil model and Compositional Model. The black oil model uses some correlations to predict physical properties using two basic properties like specific gravity of oil and gas and boiling point. The compositional model uses an equation of state to predict all physical properties at a given temperature and pressure.
For gas-condensate systems, the compositional model shall be used. For lower gas-condensate ratios selection of the best model is difficult. The compositional model may not be as good as the Black oil model. The general practice with steady-state simulators is using the black oil model for gas oil ratios less than 3500 SCF/bbl.
Heavy ends in well fluids are usually characterized by Pseudo components or cuts. Usually, components heavier than Hexane (C6+) are demonstrated by one or more cuts. Generally, the more the number of cuts, the more accurate predictions will get. Simulators usually use two or more physical properties for modeling a heavy cut, e.g. molecular weight and normal boiling point. These properties are the results of PVT analysis.
Pipeline Elevation profile
Specifying pipeline elevation profile in the simulation should be done with great accuracy, because it may have a significant effect on pressure drop calculation. For example, a liquid holdup in inclined pipe sections with upward flow direction is greater than holdup in a downward flow. Hence, the elevational pressure drop in the uphill part is higher than the pressure recovery in the downhill part.
Interpretation of results
Ideally, a pipeline should not be operated in a slug flow regime, but in practice, it may be very difficult to design a line to avoid slug flow. Generally, to change the flow regime in a slugging pipeline, the designer can take three different actions which are: reducing the pipe size, increasing pipeline operating pressure (e.g. by choking the flow at the wellhead), and using the gas lift in the wells. However, it should be noted that pipelines may be operated successfully in slug flow as long as the downstream equipment is designed for slugging effects.
Simulation results may show that the flow regime is stratified which is an excellent flow regime. But, in turn down operations, terrain-induced slugging may happen which may cause severe operating conditions.
For most pipelines, the worst conditions for liquid holdup and slugging happen at extreme operating conditions like turndown flow, very high/ very low ambient temperatures, rich gas /condensate mixtures, etc. Simulation results for these cases should also be investigated.
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