In a system design, the entire system from the reservoir to the end user has to be considered to determine applicable operating parameters; flow diameters and flow rates; insulation for tubing, flowlines, and manifolds; chemical injection requirements; host facilities; operating strategies and procedures; etc., to ensure that the entire system can be built and operated successfully and economically. All production modes, including start-up, steady state, flow rate change, and shutdown throughout the system life, must be considered.

Operating strategies and procedures for successful system designs are developed with system unknowns and uncertainties in mind and can be readily adapted to work with the existing system, even when that is different from that assumed during design. In deepwater projects, the objective of operating strategies is to avoid the formation of hydrate or wax plugs at any time, especially hydrates in the subsea system including wellbores, trees, well jumpers, manifold, and flowlines during system operation.

Although the operations are time, temperature, and pressure dependent, a typical operating procedure is as follows:

  • Operate the flowlines in an underpacked condition during steady state; for example, maintain a sufficient gas void fraction to allow successful depressurization to below the hydrate dissociation pressure at ambient temperatures.
  • For a platform shutdown, close the boarding valves and tree as close to simultaneously as possible in order to trap the underpacked condition.
  • Design the insulation system to provide enough cooldown time to address facility problems before remedial action is needed, and perform the interventions.
  • Inject hydrate inhibitor into the well, tree, jumpers, and manifolds.
  • Blow down the flowline to the pressure of fluid below the hydrateforming pressure.
  • Flush flowlines with hot oil prior to restart from a blowdown condition.
  • Start up the wells in stages, while injecting hydrate inhibitor. Continue hydrate inhibitor injection until the warm-up period for the well, tree, jumpers, and manifold has passed and enough gas has entered the flowline to permit blowdown.

The systems are normally designed to have a 3-hr no-touch time during which no hydrate prevention actions are required. Blowdown is carried out only during longer, less frequent shutdowns, and about three times per year. The logic charts for start-up and shutdown serve as an outline for the operating guidelines.

The flowlines must be pigged to remove any residual, uninhibited fluids from them. The flowlines are then pressured up to system pressure to avoid any problems caused by a severe pressure drop across the subsea choke and to make manifold valve equalization easier when it is time to switch flowlines. The next step is to start up the well that heats up the fastest, remembering to inject hydrate inhibitor at upstream of the choke while this well is ramping up. When the system is heated, hydrate inhibitor injection can stop. For this case, once the tree has reached 150 F, MeOHinjection can be stopped. The temperature of 150 F has been determined to provide 8 hr of cooldown for the tree.

Well Start-Up and Shut-Down

The subsea tree’s production wing valve (PWV) is designated as the underwater safety valve (USV). The production master valve (PMV) is manufactured to USV specifications, but will only be designated for use as the USV if necessary. The well has a remotely adjustable subsea choke to control flow. The subsea choke is used to minimize throttling across the subsea valves during start-up and shutdown.

Well Start-Up

The following start-up philosophies are used for cases in which well start-up poses a risk for flowline blockage, particularly if a hydrate blockage is suspected based on the flow assurance study from the design phase:

  • Wells will be started up at a rate that allows minimum warm-up time, while considering drawdown limitations. There will be a minimum flow rate below which thermal losses across the system will keep the fluids in the hydrate-formation region.
  • It may not be possible to fully inhibit hydrates at all water cuts, particularly in the wellbore. High water-cut wells will be brought on line without being fully inhibited. Procedures will be developed to minimize the risk of blockage if an unexpected shutdown occurs.
  • The system is designed to inject hydrate inhibitor (typically methanol) at the tree during start-up or shutdown. The methanol injected during initial start-up will inhibit the well jumpers, manifold, and flowline if start-up is interrupted and blowdown is not yet possible.

Well Shut-down

Well shutdown also poses a significant hydrate risk. The following philosophies may be adopted during shutdown operations:

  • The subsea methanol injection system is capable of treating or displacing produced fluids with hydrate inhibitor between the manifold and SCSSV following well shutdown to prevent hydrate formation.
  • Hydrate prevention in the flowlines is accomplished by blowing the flowline pressure down to less than the hydrate-formation pressure at ambient seabed temperatures.
  • Most well shut-downs will be due to short-duration host facility shutdowns. The subsea trees, jumpers, and flowlines are insulated to slow the cooling process and allow the wells to be restarted without having to initiate a full shutdown operation.

Flowline Blowdown

Why Do We Blow Down?

The temperature of a flowline system is kept from forming hydrates by the heat from the reservoir fluids moving through the subsea flowlines during steady-state operation. When well shutdown occurs, and the pressure in the system is still high but the temperature of the system will decrease as heat is transferred to the ambient environment, hydrates may form in the flowline. Once the blowdown of the fluid pressures to below the hydrate-formation pressure corresponding to the environmental temperature has been performed, it is safedfrom the hydrate-formation point of the viewd to leave the system in this condition indefinitely.

When Do We Blow Down?

The blowdown is carried out based on several factors:

  • Flowline pressure;
  • Available thermal energy in the system;
  • Ability of the insulation to retain heat.

When the flowline is shut down, the countdown to the hydrateformation temperature begins. Several hours of no-touch cooldown time is expended before hydrate inhibitor injection or blowdown is required.

The base of the risers is the most at risk for hydrate formation in a subsea tie-back system. Riser bases have the least amount of insulation, lowest temperature fluid at the seafloor, and, once the system is shutdown, fluids in the vertical section condense and flow downhill to pool at the riser base. Therefore, this section of the flowline must be treated early to prevent hydrate formation. The hydrate inhibitor is injected at the platform and this will mix with the fluids at the riser base and will effectively lower the temperature at which gas/water interfaces form hydrates. This will allow us to avoid blowdown for several more hours.

Once a blowdown operation has begun, the topside PLC timer is used to determine the length of time to blow the system down. Following a shutdown, all of the flowlines will need to be completely blown down by the end of 12th hour, which is different depending on the project’s requirement. Following an extended shutdown that resulted in blowdown of the subsea system, the remaining fluids must be removed from the flowlines before the flowlines can be repressurized. The fluids remaining in the flowlines will have water present and the temperature will be the same as the water temperature. When cold, high-pressure gas is introduced to water, hydrates can form. One option is pigging the flowline to remove residual fluids; sometimes displacement with hot oil is performed without pigging. Prior to beginning a pigging operation, ensure that adequate quantities of methanol are on board the platform for start-up operations and subsequent shutdown or aborted start-up.


[1] E.G. Hammerschmidt, Gas Hydrate Formation in Natural Gas Pipelines, Oil & Gas Journal vol. 37 (1939). No. 50.

[2] A.A. Kaczmarski, S.E. Lorimer, Emergence of Flow Assurance as a Technical Discipline Specific to Deepwater: Technical Challenges and Integration into Subsea Systems Engineering, OTC 13123, Offshore Technology Conference, Houston, 2001.

[3] E.D. Sloan, Hydrate Engineering, Monograph 21, Society of Petroleum Engineers, Richardson, , Texas, 2000.

[4] F.M. Pattee, F. Kopp, Impact of Electrically-Heated Systems on the Operation of Deep Water Subsea Oil Flowlines, OTC 11894, Offshore Technology Conference, Houston, 2000.

[5] S.E. Lorimer, B.T. Ellison, Design Guidelines for Subsea Oil Systems, presented at Facilities 2000: Facilities Engineering into the Next Millennium, (2000).