Challenges in developing subsea high-pressure/high-temperature (HP/HT) prospects relate to the extremes of the operating envelope. The first key decision is around how the extreme pressure will be handled. Two options are available: a fully rated subsea system and a subsea High Integrity Process Protection System (HIPPS).

Both options should be evaluated based on criteria such as constructability, cost and

Figure 1. The use of highly insulated systems can offer significant pipeline survival time, reducing the requirement for depressurization and subsequent complex cold startup. An insulation U value of around 0.7 w/m2K has been achieved in recent subsea HP/HT long distance tiebacks. (All figures courtesy of HP/HT Solutions)
inherent safety. Although fully rated systems are often considered inherently safer, the specific nature of an HP/HT tieback should be carefully considered. If a failure occurs and the full subsea system reaches its design pressure which may be greater than 10,150 psi (700 bar), the volume of gas in a long distance tieback could present a significant risk to the host platform should a secondary failure occur. By employing a subsea HIPPS system, high-pressure gas can be contained in a smaller inventory upstream of the HIPPS valves, far away from the host platform.

Overpressure protection
A comprehensive and robust overpressure protection philosophy should be one of the first deliverables for any HP/HT tieback project. Then, the subsea architecture must be based around flow assurance, operability and constructability. In HP/HT gas condensate developments subsea design is usually dominated by hydrate mitigation. The solution used in fields developed to date is a highly insulated subsea flowline. High wellhead flowing temperatures and the use of pipe-in-pipe insulation with U-values as low as 0.7 W/m2K has allowed subsea step-outs of up to 28 to 31 miles (45 to 50 km) from the host platform. An insulated “hot” system design provides a reliable and simple solution for normal, steady-state operating conditions.

The topsides facilities required for normal operation may be as simple as an inlet slug-catcher reception vessel. Although high wellhead flowing temperatures are key in allowing long-distance tiebacks, a limitation is the maximum feasible inlet design temperature of the main subsea pipeline. This is usually dictated by upheaval buckling considerations and is often below the potential maximum temperature of the produced fluids. In such cases, the subsea design must incorporate features that allow temperature reduction of the fluids prior to entry to the export line. If the wells can be drilled remote from the central manifold the infield flow lines may dissipate sufficient heat before co-mingling at the manifold and routing to the export pipeline. If remote wells are not feasible or economic a cooling spool may be required downstream of the subsea manifold. Such a spool must allow sufficient heat to be dissipated at the maximum design production rate to meet the inlet pipeline temperature specification. During a system shutdown, however, the spool will cool exponentially more rapidly than the main export flow line. If hydrate formation is to be prevented, this cooling spool must be designed such that it is free draining, a feature which adds complexity and cost to the subsea design. It will, however, ensure no liquid buildup is possible and therefore removes any potential of a hydrate formation during a shutdown. A cooling spool adds operational limitations by reducing the turndown capability of the system. System turndown is based on the minimum flow rate that ensures arrival temperature at the platform is above hydrate formation temperature. Including a cooling spool increases heat loss as the flow rate drops; this in turn reduces arrival temperature and limits achievable turndown rate.

Preventing hydrate formation
With an HP/HT system, not only high temperature presents problems. If the system has been
Figure 2. Schematic of HP/HT subsea wellhead showing heating spool.
shut in fluids will begin to cool. As pipeline bulk fluid temperature approaches the hydrate formation temperature the system must be blown down. The system is usually blown down to around 10 barg. This reduces hydrate formation temperature to below ambient seabed temperature, removing the risk of hydrate blockage. To prevent hydrate formation on restart, liquids held up over the length of the pipeline must be inhibited before the pressure can be increased to normal operating pressure. To do this, methanol must be injected at the wellhead and swept through the length of the line by flowing a single well at low rates. The startup flow rate must be minimized to prevent significant backpressure in the main pipeline. To fully inhibit a long tieback of 28 miles (45 km) at these low rates can take up to 18 hours, a significant ramp-up time for a subsea tieback.

The initial stages of this restart process involve opening the choke with potentially a differential pressure of over 600 barg across the valve. The associated Joule-Thompson cooling as the valve is opened can lead to temperatures down to -156°F (-70°C). These conditions have required the qualification of subsea chokes to meet these minimum temperature requirements, some 40° below conventional subsea choke design. The low temperatures on startup give rise to a significant hydrate formation risk. To combat this, large volumes of methanol must be injected upstream of the choke. This requires a specialist pump design that can cater to high pressure and relatively high volume compared to typical chemical injection pumps. These pumps also become critical to the operability of the system and must have a high level of availability.

Although the choke and limited sections of line downstream can be designed to these very low temperatures it would be impractical to attempt to design the full subsea tieback to a -95°F (-70°C) minimum design temperature. This presents a problem. The system is designed to retain heat in normal operation. It follows that the insulation system will not allow any heat input from the ambient conditions to warm the fluids during start up. On startup, a cold front below -59°F (-50°C) would extend through a large portion of the export line. The almost counter-intuitive solution is the inclusion of a heating spool downstream of the production choke. This spool is merely a section of un-insulated line to allow heat input from the ambient seabed conditions. This heat input limits the minimum design temperature for the downstream system. The typical length of the warming spool is in the order of tens of meters. This un-insulated section must be free draining to remove any hydrate risk during a shutdown.

Operation of a “hot” HP/HT subsea tieback is simple for normal operating conditions. It can offer a low OPEX solution with high reliability and availability when compared to a continuous inhibition system that relies on additional topsides equipment. However, start up and shutdown conditions pose the significant challenges. Pipeline and insulation system designs also require significant CAPEX investment, a cost increased significantly by the requirement for exotic CRA materials given the corrosive nature of the reservoir fluids and the high operating temperature of the pipeline.

It is important that full field-life costs are considered in detail during the concept selection phase of any potential HP/HT development. The “hot” design concept may be compared to a continuously inhibited system using MEG injection to prevent hydrate formation. Such a system requires more complex topsides equipment and investment and availability may be lower. These negative aspects may be outweighed by the opportunity to run the pipeline cold, reducing the requirement for exotic materials of construction and insulation. The restart and turndown issues are also significantly reduced when a continuous inhibition system is used.