Flow Assurance Studies, Steady-State Modeling

Steady-state Modeling

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.

Pipeline Sizing

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

Steady-state simulation

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.

Saiedeh Nikraftar


Flow Assurance Studies: Hydrate Management


In 1930, Hydrate management started to become the biggest challenge in the pipeline. Pipelines blocked by ice-like plugs which are crystalline compounds that occur when water forms a cage-like structure around smaller guest molecules. Hydrate looks like water ice but its properties are much different. It’s been known as burning ice because it burns when it gets closed to a lighted match.

Hydrate Structure

Hydrate normally forms in one of the repeating crystal structures: structure I (SI), structure II (SII), structure H (SH). Structure I (SI) is a body-centered cubic structure form with small natural gas molecules found in deep oceans. Structure II (SII), is a diamond lattice within a cubic framework, which forms when natural gases or oils contain molecules larger than ethane but smaller than pentane. Structure II (SII) commonly occurs in hydrocarbon production and processing conditions. Structure H (SH) named for its hexagonal framework has cavities large enough to contain molecules the size of common components of naphtha and gasoline.

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Hydrate Formers

The three major elements of hydrate formation are:

  • Water either free, dissolved or in vapor phase
  • Hydrocarbon molecules: molecules ranging in size from methane to Butane including CO2, H2S, N2.
  • Low temperature and high pressure (e.g. 4°C and 20 barg or 20°C and 100 barg)

And the three conditions which favor hydrate formation are:

  • Turbulence (high velocity, agitation)
  • Free water phase
  • Nucleation sites (elbows, tees, valves, scales, corrosion products)

There are different statements in literature about importance of free water in hydrate formation. Previously, it was believed that free water phase is essential and pipelines don’t usually have enough residence time for hydrates to form from water vapor in gas phase. But recently, cases have been observed where hydrate forms in gases containing water vapor, without free water condensation. Hydrate from water vapor forms snow-like particles which may form a plug in restrictions. Although free water is not essential, but it enhances the hydrate formation very much. In addition, Gas –water interface is a good nucleation site for hydrate.

Hydrate causes many operational problems like blocking of pipeline, valves and instruments, plugging of heat exchangers, etc. This is specially important in control valves which have small orifices

Hydrate formation is usually a problem in gas flowlines but not in oil flowlines (except for areas such as ultra-deep offshore production) because:

  • Oil systems mainly contain heavier hydrocarbons like C5+ which are not hydrate forming molecules. In addition, they interfere with the growth of hydrate crystals.
  • Produced water from oil wells contains salts, whereas the water accompanying a gas is generally condensed fresh water. Electrolytes inhibit substantially the formation of hydrates (1C by 20g/l of equivalent of NaCl)

Hydrate Management: Inhibition

There are four classical mitigations for Hydrate formation:

  • Remove water from the system, generally by the Glycol process. This method is reliable and mainly used for drying gases for gas export. This method may not be cost-effective for gases at wellheads or at the flowlines entry.
  • Temperature preservation, keeping the temperature above the hydrate formation region by heating or insulating the lines.
  • Hydrate inhibitor injection. Continuous injection of inhibitors is cost-effective only for systems with low water contents and required temperature depression of 15-20° C.
    Two different types of inhibitors are available:
    1- Thermodynamic inhibitors (THI) like Methanol and Glycols act like anti-freeze chemicals and displace the hydrate region.
    2- Low dosage hydrate inhibitors (LDHI), including Kinetic hydrate inhibitors (KHI) and Anti-agglomerates (AA). Kinetic inhibitors prevent hydrate crystal growth and anti-agglomerates use a surfactant to stabilize the water-hydrate phase as small droplets in the liquid phase and prevents hydrate growth at the agglomeration stage.

Glycol vs. Methanol

Among all types of glycols, TEG and TREG are too soluble and too viscous for general use. The most popular inhibitors are MEG, DEG, and methanol. Methanol may be used effectively at any temperature. DEG is not recommended below -10°C because of its viscosity and the difficulty of separation if the oil is present. Above -10°C it might be preferred as there is less vaporization on loss than MEG or Methanol. Recovering methanol is not economical. However, if the gas stream is dried downstream in a TEG unit, methanol can be easily recovered in the TEG regenerator overhead.

Generally, using Glycol is economic where the amount of gas to be inhibited is considerable and continuous injection is required. While Methanol is usually used for temporary usages, low gas volumes, and where the required temperature depression is not much.

As a rule of thumb glycol units are used when required methanol injection exceeds 120 l/h.

Inhibitor Usage

The minimum inhibitor concentration may be calculated by semi-empirical correlation of Hammerschmidt or by using computer simulation.

Hammerschmidt equation matches very well with laboratory equilibrium data for hydrate inhibition with methanol solutions up to about 25% and glycol to about 60-70%:

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W: Inhibitor concentration in liquid water, wt%

Δt: Hydrate formation temperature depression

M: Inhibitor molecular weight

Ki: 1297 for Methanol, 2220 for MEG & DEG

For methanol concentrations up to 50% the Nielsen-Buckling correlation provides better accuracy:

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In practice, the amount of required inhibitor depends on system configuration, location and method of injection, system dynamics, etc. Most operators adjust injection rate by try and error during start-up.

Typically, the required free water concentration of methanol in onshore pipeline is 20 wt% while for offshore pipeline, it may exceed 50 wt% due to high pressures. A recent study has shown that hydrate in under-inhibited systems with methanol, forms faster and hydrate plugs stick to the pipe wall more aggressively.

For more accurate estimation of hydrate formation temperature, computer simulation is recommended. The available commercial software for hydrate prediction are:

  • PVTSim from Calsep, which can be linked to various simulation software like Olga.
  • Multiflash from Infochem; ‘Multiflash Hydrate Package’ is an optional add-on to Multiflash package in Pipesim.
  • ‘DBR Hydrate’ package which is part of Pipeflo from Neotec

In order to estimate the required inhibitor flow rate, following steps should be followed:

  • Develop phase envelope together with hydrate equilibrium curve.
  • Simulate the pressure – temperature profile in the system at the worst case operating conditions.
  • Estimate the amount of subcooling in the system relative to hydrate formation curve.
  • For Δt<25°C consider kinetic inhibitors and for Δt>25°C, consider the use of thermodynamic inhibitors.
  • Draw hydrate formation curve in systems containing different amount of inhibitors in order to locate the system P-T at the ‘no hydrate’ zone of P-T curve. (See figure 2)

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Inhibitor loss

Inhibitor loss includes:

  • The amount of inhibitor lost to the gas phase
  • The amount of inhibitor lost to the condensate phase
  • The amount of inhibitor lost in regeneration system

Methanol is very volatile and its loss to the vapour phase is considerable. Methanol vaporisation loss can be estimated from figure 3.

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Glycols, however, have very low vapor pressure and its vapor phase loss is very small.

As a rule of thumb, at 4°C and P>68 barg maximum amount of methanol loss to vapor phase is 1 lbm/MMscf for every wt% Methanol in free water phase. And for glycol the maximum amount of its loss to vapor phase is 0.002 lbm/MMscf of gas.

Methanol dissolves in paraffinic, naphthenic and aromatic hydrocarbons, but its solubility in aromatics is much better relative to paraffinic hydrocarbons. Methanol solubility in liquids depends on temperature and methanol concentration.

As a rule of thumb, Methanol concentration dissolved in condensate is 0.5 wt%. And for MEG, mole fraction of MEG in a liquid hydrocarbon at 4C and P>68 barg is 0.03% of mole fraction of MEG in water phase.

Methanol is often not recovered so no regeneration is needed.

MEG and DEG are lost in the regeneration system by carry-over from the regenerator and separator. The amount of carry-over is usually less than 25 kg/106 Sm3 gas flow rate.

Hydrate as a Source of Energy

Hydrates are not always undesirable. Methane hydrates are big sources of energy. There are huge amount of gas hydrates in ocean floor. Under high pressure and low temperature, methane hydrates form. To date, Extracting methane from methane hydrates and exploiting the energy within it is a big engineering and environmental challenge.

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  • GPSA, Engineering Data Book Gas Processing, 12th ed.

Saiedeh Nikraftar

14 Nov. 2014