Modeling, simulation mitigate flow assurance risk

Representative fluid hydrate curve for the case study.

Chemicals used for hydrate inhibition are either thermodynamic inhibitors (THI) or what is referred to as low dosage hydrate inhibitors (LDHI). A combination of both has been used successfully for hydrate inhibition. Thermodynamic inhibitors alter the thermodynamic properties of the fluid such that the stability of hydrates is either prevented or moved to lower temperatures. The LDHI work either as kinetic hydrate inhibitors (KHI) to delay the time for hydrates to form, or as anti-agglomerates (AA) to prevent precipitated hydrate crystals from coalescing into plugs that may block the flowline.

Insulation selection

Following the decision on a suitable flowline size based on hydraulic capacity requirements, the choice of flowline insulation arguably is the next most critical decision surrounding a long tieback. The insulation performance needs to be specified primary to meet the required fluid arrival temperatures during steady-state operation over the life of the field. This is assessed by steady-state thermo-hydraulic studies. A secondary requirement is sufficient cooling time during shutdown without hydrates forming (sometimes referred to as hands-off time), during which time arrangements can be made either to take preventive action, e.g. blowdown, or to resolve the cause of the problem and restart production.

Optimal insulation performance balances cost and risk and is determined by performing a transient heat loss analysis with the aim being to protect the flowline from hydrates typically for eight to 12 hours after shutdown.

Production considerations

Unmanaged slugging, which results from operating within the slug flow flow-regime (hydrodynamic slugging) or due to terrain effects, can lead to operational difficulties such as separator trips. The relative velocities of the liquid and gas phases that result in hydrodynamic slugging normally can be avoided by operating outside the slug flow flow-regime. Terrain slugging, on the other hand, can be managed via topsides chokes or adequate slug catcher size. Subsea processing with separation and boosting could improve the flow regime to minimize the impact of terrain effects.

For long tiebacks, current methods for slug control should apply without the need for new slug control considerations.

During a production turndown, the reduction in total heat-flow into the system due to the reduced flowrate will result in more rapid temperature drops to within the HFT and WAT. As a result, chemical injection at a rate optimized to inhibit the production fluids from hydrate formation at the arrival temperature may be considered.

Plot of the difference between the HFT and fluid temperature after shut in for 20 hours and for each OHTC considered.

For long tiebacks, the inhibition chemical volume requirements will be substantial and hence an increase in chemical efficiency as highlighted by the ITF report will be required to provide a viable solution to the problem of storing and injecting high quantities of chemicals over long distances.

Production shutdown may be planned or unplanned. Planned shutdown could be for maintenance while unplanned shutdown can be due to unexpected operational upsets. Whatever the reason, the primary concern is formation of hydrates and measures to mitigate this risk. Hydrates typically are stable at high pressures and low temperatures and the aim of most hydrate management strategies is to shift the conditions of thermodynamic stability to lower temperatures or to reduce the pressure at which the fluids exist.

Common mitigating options and their implications for long tiebacks include:

Chemical injection (e.g. MeOH) to inhibit hydrates at the shut-in pressure. For long tiebacks, the MeOH requirements to fully inhibit hydrates for a 200+ km (124+ mi) flowline with moderate watercut will be substantial. LDHI cannot be used for extended shut-in periods as they expire after a few hours.

Flowline depressurization, or blowdown, to keep the flowline out of the hydrate formation region. This probably is the most common means of hydrate inhibition to address an unplanned shutdown where the system could be inoperative for long periods. Blowdown reduces the flowline pressure to below the hydrate formation pressure (at the ambient temperature). For long tiebacks, the time to depressurize the system will be longer, considering that the depressurization rate has to be limited to prevent excessive cooling that may lead to hydrate formation. The depressurization rate also may be limited by the flare’s maximum gas handling capacity and the riser’s minimum design temperature.

Active heating of flowlines. This has been used in some offshore environments and aims to keep the fluid above the hydrate formation or wax appearance temperatures. The most suitable heating method will be determined based on cost and efficiency but may result in significantly higher capex and opex compared to most other methods such as blowdown, especially for long tiebacks.

Other options include:

• Hot oil (e.g. diesel circulation)

• Liquid sweep-out through pigging
• A combination of methods.For example, sweep out followed by chemical treatment.

A shut-in well can either be started up into a pressurized flowline or a flowline that has been depressurized to avoid hydrate formation. The main concern in the latter case is low temperature generation due to Joule-Thompson (J-T) cooling across the well choke, especially if a pressurized gas cap forms in the well. When the well is started up into a depressurized flowline, the pressure drop across the well choke on start up could result in temperatures as low as -45° C [-113° F] taking the fluid into the hydrate formation region. Chemical injection is required to protect downstream sections of the flowline from hydrates due to this low temperature travel along the flowline and should continue until the system flowline is sufficiently warmed to above the hydrate formation temperature. For long tiebacks, more time is required before the system warms up sufficiently. As a result, inhibiting chemicals need to be injected for longer periods, increasing the total volume requirement. The optimal start-up rate, subject to the available chemical injection rate, topsides facilities liquid handling capacity, and liquid buffer volume available, must be determined. The aim also is to determine a start-up rate that will minimize flowline back pressure.

Case study

Of the transient operations that require flow assurance considerations, production shutdown is analyzed in more detail to evaluate the impact of the key system parameters and the mitigating action highlighted for hydrate management. The value of simulation tools is demonstrated at each stage of the analysis and results are presented for a hypothetical offshore field development.

The development is for a 200-km (124-mi) single well tieback via a 12-in. (30-cm) flowline to a host facility such as an FPSO in a water depth of 1,500 m (4,921 ft) and producing at a rate of 45,000 b/d, a GOR of 920 cf/bbl, and 25% watercut. A single production rate is considered for simplicity. The composition applied has a hydrate line given the accompanying curve.

Additional basis data applied are as:

Arrival and ambient conditions

Arrival pressure at FPSO: 15 bar (1.5 MPa)

Minimum temperature during normal (steady-state) production: 25° C (77° F)

Water temperature at 1,500 m (4,921 ft) = 4° C (39° F)

Available FTHP = 185 bar (18.5 MPa)

Flowing tubing head temperature (FTHT) = 65° C (149° F)

A minimum shut-in duration of 20 hours

Mitigation selection

The importance of fluid sample integrity is the first major step to establish flow assurance challenges and to determine mitigation options. From the fluid sample, the region for hydrate formation can be determined accurately using PVT and physical property packages that apply advanced multiphase fluid equilibria methods.

Once the hydrate curve has been determined, the minimum required arrival temperature can be specified. The overall heat transfer coefficient (OHTC) required to deliver the fluids to the topsides at the required temperature is determined.

For this analysis, the transient multiphase flow simulator OLGA is used to generate the flowline temperature profile during steady state production based on OHTC values of 1, 0.7, and 0.5 W/m2K. A summary of the arrival temperatures obtained for each OHTC value considered is given in the table above. This shows that the OHTC of 0.7 W/m2K is sufficient to meet the arrival temperature requirement for the system considered.

Once the insulation performance required for steady state has been determined, the impact of each OHTC on cooldown can be assessed.

A useful means of assessing the rate of fluid heat loss and consequent approach to the hydrate formation region is to plot the difference between the fluid temperature and the hydrate formation temperature (HFT) at the existing flowline pressure. A positive value of the temperature difference is indicative of the fluid being in the hydrate region.

This temperature difference for the three OHTC cases shows that for a required 20-hour “hands-off” period before action is taken to further inhibit the system or to restart production, the 0.7 W/m2K OHTC case offers sufficient insulation performance.

Hot oil (e.g. diesel or similar stabilized oil) is another consideration for hydrates inhibition during production shutdown. A looped system to circulate the heated oil is required. Simulation results show that if the aim is to keep the flowline warm, the required injection rate and temperature will be impractical because the hot oil cools to the ambient temperature before completing a “round-trip”. However, since the composition of typical diesel or similar stabilized oil contains no hydrate formers, the flowline can be flushed, literarily “stuffed” with the oil, and remain shut-in for extended periods without risk of hydrates forming, provided the required volume of oil is available.

Fully inhibiting a 200-km (124-mi) flowline with a chemical such as methanol under the shut-in conditions and watercut requires impractical quantities of methanol. LDHI for inhibiting the flowline at shutin also rules itself out since it has an expiration period. Therefore, for this case study, chemical injection alone can be ruled out for hydrate inhibition.

In this analysis, blowdown is selected as the hydrate prevention method of choice based on its effectiveness and low cost. Blowdown is simulated to start after a 12-hour shut-in period from a settle-out pressure of 90 bar (9 MPa). Twelve hours is selected to allow additional blowdown time while the flowline is still in the hydrate-free operating region. It is intended to depressurize the flowline to 6 bar (0.6 MP) as the flowline will be outside the hydrate risk envelope at the ambient temperature.

Initially, blowdown was to be via a 6-in. (15-cm) valve and the blowdown route via the topsides flare system. The simulation, however, showed the system would not depressurize quickly enough to 6 bar, thus indicating the need for an additional blowdown route. When a two-point depressurization is applied with the second depressurization point at the flowline inlet, an improved depressurization rate sufficient to prevent the flowline from exposure to hydrate formation conditions is achieved.

Based on this case study, the following conclusions are drawn:

• Insulation performance is crucial in the flow assurance of deepwater long tiebacks during both steady-state and transient operations
• Blowdown of long tiebacks can take a long time. This study showed that the rate of heat loss in long tiebacks could easily exceed the rate of depressurization in an attempt to keep the fluid out of hydrate zone. As a result, in addition to depressurizing via the topsides, adopting an additional depressurization route such as from the flowline inlet probably via an additional line installed for this purpose, overcomes the lengthy blowdown times associated with long tiebacks and result in hydrate prevention
• Hot oil circulation for long tiebacks in deepwater requires lots of storage. If such volumes are available, the hydrate free oil can be used to flush and fill the flowline for extended periods
• Based on the current efficiency levels of hydrate inhibitors, chemical treatment, when the only method of hydrate prevention, is not an option for long tiebacks. A combination of methods such as blowdown followed by chemical treatment offers one of the most viable solutions
• Simulation tools have been shown to evaluate the technical feasibility of a number of hydrate management options with a high degree of detail and a reasonable level of certainty.

Editor’s Note: This is an edited version of the paper presented at PennWell’s 2008 Offshore West Africa Conference & Exhibition in Abuja, Nigeria.