As mentioned earlier, flow assurance is an engineering analysis process of developing a design and operating guidelines for the control of solids deposition in subsea systems. Depending on the characteristics of the hydrocarbons fluids to be produced, the processes corrosion, scale deposition, and erosion may also be considered in the flow assurance process. The main part of the flow assurance analysis should be done prior to or during the earlier front-end engineering and design (FEED) process.

  • Fluid characterization and flow property assessments;
  • Steady-state hydraulic and thermal performance analyses;
  • Transient flow hydraulic and thermal performance analyses;
  • System design and operating philosophy for flow assurance issues.

Detailed explanations for each issue are given in the following sections. Some issues may occur in parallel, and there is considerable “looping back” to earlier steps when new information, such as a refined fluids analysis or a revised reservoir performance curve, becomes available.

Fluid Characterization and Property Assessments

The validity of the flow assurance process is dependent on careful analyses of samples from the wellbores. In the absence of samples, an analogous fluid, such as one from a nearby well in production, may be used. This always entails significant risks because fluid properties may vary widely, even within the same reservoir. The key fluid analyses for the sampled fluid are PVT properties, such as phase composition, GOR (gas/oil ratio), and bubble point; wax properties, such as cloud point, pour point, or WAT; and asphaltene stability.

Knowledge of the anticipated produced water salinity is also important, but water samples are seldom available and the salinity is typically calculated from resistivity logs. The composition of the brine is an important factor in the hydrate prediction and scaling tendency assessment. In cases where a brine sample is not available, predictions about composition can be made based on information in an extensive database of brine composition for deepwater locations.

The hydrate stability curves are developed based on PVT data and salinity estimates, and methanol dosing requirements are also obtained. A thermal-hydraulic model of the well(s) is developed to generate flowing wellhead temperatures and pressures for a range of production conditions. Then wellbore temperature transient analyses are carried out.
File:Typical Flow Assurance Process.png
Typical Flow Assurance Process
File:Typical Oil, Water, and Gas Production Profiles with Time.png
Typical Oil, Water, and Gas Production Profiles with Time

The dosing calculations of the hydrate inhibitor, such as methanol or MEG, indicate how much inhibitor must be added to the produced water at a given system pressure to ensure that hydrates will not form at the given temperature. Hydrate inhibitor dosing is used to control hydrate formation when system temperatures drop into the range in which hydrates are stable during the steady state or transient state of a subsea system during start-up, normal operations, and shutdown. The inhibitor dosing requirements are used to determine the requirements for the inhibitor storage, pumping capacities, and number and size of inhibitor flowlines in order to ensure that the inhibitor can be delivered at the required rates for treating a well and subsea system during start-up, normal operation, and shutdown.

Steady-State Hydraulic and Thermal Performance Analyses

The steady-state flowline model can be generated with software such as PIPESIM or HYSYS. Steady-state modeling has several objectives:

  • To determine the relationship between flow rate and pressure drop along the flowline. The flowline size is decided based on the maximum allowable flow rate and the minimum allowable flow rate.
  • To check temperature and pressure distributions along flowlines in a steady-state condition to ensure that the flowline never enters the hydrate-forming region during steady-state operation.
  • To choose an insulation combination that prevents the temperature at the riser base of a tie-back subsea system from falling below the minimum value for cooldown at the maximum range of production rates. The riser base temperature is determined as a function of flow rate and the combined wellbore/flowline insulation system.
  • To determine the maximum flow rate in the system to ensure that arrival temperatures do not exceed any upper limits set by the separation and dehydration processes or by the equipment design.

Transient Flow Hydraulic and Thermal Performances Analyses

Transient flowline system models can be constructed with software packages such as OLGA and ProFES. Transient flowline analyses generally include the following scenarios:

  • Start-up and shutdown;
  • Emergent interruptions;
  • Blowdown and warm-up;
  • Ramp up/down;
  • Oil displacement;
  • Pigging/slugging.

During these scenarios, fluid temperatures in the system must exceed the hydrate dissociation temperature corresponding to the pressure at every location; otherwise, a combination of an insulated pipeline and the injection of chemical inhibitors into the fluid must be simulated in the transient processes to prevent hydrate formation.


Hydrate inhibitor should generally be injected downhole and at the tree during start-up. When the start-up rate is high, inhibitor is not required downhole, but the hydrocarbon flow should be treated with inhibitors at the tree. Otherwise, the hydrocarbon flow is required to be treated with inhibitors downhole. Once the tree is outside the hydrate region, hydrate inhibitor can be injected at the tree and the flow rate increased to achieve system warm-up. The start-up scenario is different for the combination of a cold well with a cold flowline and a hot flowline.


Shutdown scenarios include planned shutdowns and unplanned shutdowns from a steady state and unplanned shutdowns during warm-up. In general, the planned and unplanned shutdowns from the steady state are the same with the exception that for a planned shutdown, hydrate inhibitor can be injected into the system prior to shutdown. Once the system is filled with inhibited product fluids, no further inhibitor injection or depressurization is needed prior to start-up.

After shutdown, the flowline temperature will decrease because of heat transfer from the system to surrounding water. The insulation system of the flowline is designed to keep the temperature of fluids above the hydrate dissociation temperature until the “no-touch time” has passed. When considering minimum cooldown times, the “no-touch time” is the one in which operators can try to correct problems without having to take any action to protect the subsea system from hydrates. Operators always want a longer “no-touch time,” but it is a cost/benefit balancing problem and is decided on a project-by-project basis. Analyses of platform operation experience in West Africa indicate that many typical process and instrumentation interruptions can be analyzed and corrected in 6 to 8 hours.

Let’s use a tie-back subsea system in West Africa as an example. If the system is shut down from a steady state, the first step is to see if the system can be restarted within 2 hours. If so, start-up should begin. If not, one option for hydrate control is for the riser to be bullheaded with MeOH (if MeOH is chosen as a hydrate inhibitor) to ensure that no hydrates can form in the base of the riser where fluids are collecting.

Next the tree piping will be dosed with methanol. After that, the fluid in the flowline will begin to be fully treated with methanol. Once 8 hours have passed, operators must determine if the system can be started up or not. If it can be started, they will proceed to the start-up procedure outlined previously. If it cannot be started up, the flowlines will be depressurized. The intention of depressurization is to reduce the hydrate dissociati temperature to below the ambient sea temperature. Once the flowlineshave been depressurized, the flowlines, jumpers, and trees are in a safe state. If the wells have been shutdown for 2 days without a system restart, then the wellbores need to be bullheaded with MeOH to fill the volume of the wellbore down to the SCSSV. Once these steps have been taken, the entire system is safe.


To keep the flowline system out of the hydrate-forming region when the shutdown time is longer than the cooldown period, flowline blowdown or depressurization may be an option. The transient simulation of this scenario shows how long blowdown and liquid carryover during blowdown take. The simulation also indicates whether the target pressure to

avoid hydrate formation can be reached.
File:Liquid Carryover versus Blowdown Time.png
Liquid Carryover versus Blowdown Time


During the warm-up process, hydrate inhibitor must be injected until the flowline temperatures exceed the hydrate dissociation temperature at every location for a given pressure.
File:Effect of Flowline Insultation on Warm-Up from Cold Earth.png
Effect of Flowline Insultation on Warm-Up from Cold Earth

Hot oiling also warms up the pipeline and surrounding earth, resulting in a much longer cooldown time during the warm-up period than is accomplished by warming with product fluids. This gives more flexibility at those times when the system must be shutdown before it has reached steady state.

Riser Cooldown

The most vulnerable portion of the subsea system, in terms of hydrate formation, is typically the riser base. The steady-state temperatures at the riser base are near the lowest point in the whole system. The available riser insulation systems are not as effective as the pipe-in-pipe insulation that is used for some flowlines. The riser is subject to more convective heat transfer because it has a higher current velocity than a pipeline and, finally, it may be partially or completely gas filled during shutdown conditions, leading to much more rapid cooling.


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