During the shutdown of subsea systems, there is a high risk of hydrate formation in the flow line due to the low ambient (seabed) temperature. Hydrates are ice-like crystals that form from water and light hydrocarbons at high pressure and low temperature, and can grow large enough to form plugs that impair or completely block the flow. Thus, before the system cools down to below the hydrate formation temperature (HDT), it must be safeguarded from hydrate formation.

For planned shutdowns, the system can be protected with chemical inhibitors (e.g., methanol, low-dosage hydrate inhibitors or mono-ethylene glycol) before the shut-in. However, during unplanned shutdowns, the system is typically unprotected before the shut-in and intervention must occur after shut-in. This intervention typically involves either depressurization of the system (i.e., blowdown) or dead-oil displacement of the live production fluids.

While these techniques are usually effective, they are time-consuming and costly in terms of deferred production. Offshore production facilities with multiple subsea tiebacks, as in the Shell Exploration & Production Company (SEPCo) Habanero development in the Gulf of Mexico, face additional operational challenges owing to the different cool-down time constraints imposed by the different tiebacks. Understanding the cool-down time can allow the operator to determine how much time is available for troubleshooting the cause of the shut-in (and getting the system restarted) and how much time is available for blowdown or dead-oil displacement.

Working closely with SEPCo, Shell Global Solutions (US) Inc. carried out detailed heat-transfer simulations, which have given SEPCo vital information on flow line cool down under shut-in conditions. As a result, SEPCo has been able to strengthen its operating guidelines for managing shut-ins so that production deferment is minimized and restarts can occur more rapidly.

Heat-transfer models

The Habanero flow line is a pipe-in-pipe system with field joints at approximately 160-ft (48.8-m) intervals. While most of the flow line has polyurethane foam insulation between the carrier (inner) and the casing (outer) pipe, the field-joint annulus is filled with air for 30-in. to 35-in. on either side of a water stop. With an air-filled annulus, the field joints cool more rapidly than the rest of the flow line during a shut-in.

To account for simultaneous heat transfer in the solid pipe walls, the polyurethane foam, and the fluids in the flow line and the annulus, the field-joint geometry was accurately modeled in 3-D using computational fluid dynamics tools. This conjugate heat-transfer model was first built to obtain the steady-state conditions during normal flow (Figure 1). The steady-state solution was then used to model the transient heat-transfer during a shut-in. The model accounted for natural convection in the air-filled annulus and in the shut-in fluids. The radiation effects in the air-filled annulus were also considered.

To account for fluid redistribution in the carrier pipe during the shut-in, two liquid hold-up scenarios were evaluated: a 100% oil-filled case and a 100% gas-filled case. The initial temperature of the fluid within the flow line was set at 120°F (48.8˚C) and the ambient (seabed) temperature, to which the outer surface of the casing pipe is exposed, was set at 40°F (12.2°C) for both scenarios.

The detailed mechanism of hydrate formation under field conditions is not yet fully understood, so the cool-down time was conservatively defined as the time required (from shut-in) for the inner wall of the carrier pipe to reach the HDT of 65°F (18°C). In addition, the penetration of the HDT isotherm into the shut-in fluid with time was also calculated.

Results of simulation

The results of the simulation show that, during shut-ins, two pronounced counter-rotating convection currents are established in the air-filled annulus of the field joint. Annulus air in contact with the relatively hot carrier pipe rises, while annulus air in contact with the relatively cold casing pipe sinks (Figure 2). A stable thermal gradient forms as the denser cold air sinks and creates a cold spot. This cold spot propagates from the bottom of the un-insulated field joint and moves axially along the pipe by conduction, thereby cooling the field joint faster than the insulated pipe in pipe. While natural convection is the primary mechanism for the heat loss in the insulation-free annulus, radiative heat loss during the initial shut-in period is not negligible and must be accounted for in accurate predictions.

The average temperature of the inner surface of the carrier pipe over the length of the field joint was found to drop below the HDT for the oil- and gas-filled scenarios in 10 and 7 hours, respectively (Figure 3). Simulations of the penetration of the HDT isotherm into the shut-in fluid were used to calculate a volume-average temperature for the shut-in fluid in the field joint. The model predicted that the fluid would reach HDT in 12 hours for the oil-filled case and 9 hours for the gas-filled case (Figure 4). However, simulations have shown that the polyurethane-foam-filled pipes (the typical pipe-in-pipe sections) on either side of the field joints remain above the HDT for more than 18 hours following a shut-in.

Planning for the worst

These rigorous 3-D heat-transfer simulations have given SEPCo operations a more accurate estimate of the cool-down times and the ability to guide operational strategies for timely mitigation. Though the simulations predicted that the inner surface temperature of a shut-in, gas-filled field joint would fall below the HDT after only 7 hours, the true cool-down time is likely to be longer because:

• It takes time (usually 3 hours) for the oil and gas to redistribute in the flow line and produce gas-filled sections following a shut-in;

• The assumed initial fluid temperature of 120°F (48.8°C) is a low-flow rate (greater than 7 MMb/d) riser-base temperature. Flow rates are anticipated to be higher than this until late in the production life of the development;

• Even at low flow rates, flow-line temperatures during normal production (i.e., initial cool-down temperatures) will be greater than 120°F upstream of the riser base;

• Plugs take a specific time to form once the HDT is reached, which depends on their growth rate; and

• Owing to settling effects, the flow lines may be buried in some places and, therefore, further insulated.

In addition, the risk of a flow-stopping hydrate plug developing within a short field-joint section rather than in a long, insulated section is low. While the simulations are conservative, the results have provided SEPCo with a worst-case scenario from which to strengthen its operational procedures.