Barriers to subsea HP/HT production can be overcome

Development of a high pressure, high temperature well can cost several million dollars. The viability of such wells will be based on reservoir depth, water depth and availability of safe and reliable technology. Primary options for exploitation of HP/HT fields are based on existing technologies, namely: Subsea completion with production string, subsea wellheads, flowlines, manifold and sealine to a host processing platform. Surface wellheads using a supporting structure.

Paolo Grillo
Sugunan Natarajan
Snamprogetti UK
Development of a high pressure, high temperature well can cost several million dollars. The viability of such wells will be based on reservoir depth, water depth and availability of safe and reliable technology. Primary options for exploitation of HP/HT fields are based on existing technologies, namely:

  1. Subsea completion with production string, subsea wellheads, flowlines, manifold and sealine to a host processing platform.
  2. Surface wellheads using a supporting structure.
Subsea well completion is considered more cost-effective, as it can make use of existing platform facilities and is also more intrinsically safe. However, the gaps in subsea technology for development of HP/HT offshore reservoirs currently only permit the selection of surface installations. There are numerous impediments. Among these:

  • Although subsea wellheads are available at 15,000 psi rating for exploration and development wells, the Xmas tree connector needs improvements to reduce stress levels at high pressures and temperatures
  • Control of the hydraulically operated downhole safety valve requires a fluid supply umbilical pressurized up to 18,000 psi. Maximum fluid pressure experienced to date is around 12,500 psi. Current umbilical hose technology has a working pressure limitation of around 11,000 psi
  • Due to particularly high pressure drops, sour fluid nature and expected sand entrainment, special materials are likely to be needed to limit corrosion and erosion of the choke valves located downstream of the Xmas tree.
  • There are no large size valves available for the subsea manifold, rated at the wellhead shut-in pressure. Further limitations on subsea valves and production string are due to close coupling of the actuators, as control fluids are vulnerable to the heat from the high temperature well fluid, resulting in solids, sludge precipitation and corrosive fluids. Suitable control fluids have yet to be developed for high temperature application
  • Materials selection has to be documented against the highly corrosive conditions arising from the combined effects of process parameters and contaminants such as H2S, CO2 and chlorides.

Feasibility criteria

To increase the feasibility of an HP/HT subsea completion system, several design and development issues must be addressed. Functional specifications should be conceived at system level to ensure interactions between the working conditions of the components. For instance:

  • Due to high pressure drops the effects of disturbance in the fluid dynamics downstream of the choke valve may occur over a long segment of pipework. For the whole of this length the effectiveness of chemical injections against corrosion, scale and hydrate formations may become questionable, with subsequent implications for pipework material choices.
  • High integrity pressure protection system (HIPPS) availability requirements are governed by the degree of de-rating of equipment or components downstream of the choke, with relation to wellhead static pressure. The degree of effectiveness depends on the volume of this equipment and associated overpressurization time in case of malfunctions.
In terms of system engineering, new design criteria will have to be established for flowlines, manifold and sealine, taking care to optimize the degree of de-rating with respect to wellhead shut-in pressure. Choice of materials for application to the HP/HT environment will have to be identified, optimized and documented.

To improve safety and reliability of the subsea completion system, the maintenance schedule for each of the components of the production string up to the choke will have to be optimized, based on reliability-centered maintenance studies, as will the database for quantified risk analysis.

Development of a choke and actuator unit will be needed that is capable of handling high inlet pressures, pressure drops and temperatures with sour, corrosive and contaminated fluid control applications. The unit will have to provide long-term, reliable and safe operation as part of the HP/HT installation. This has to be achieved through a new, innovative design, choice of suitable materials and in-built capability for self-diagnostics and monitoring.

As regards wellhead and production tree equipment, existing offshore production methods are limited to 10,000 psi well pressure and temperatures of around 150°C. As HP/HT discoveries increase, pressure containment and sealing systems must be developed that permit the safe long-term development of these fields.

For the sealine, particular consideration must be given to thermal insulation, degree of de-rating, temperature decreases (with associated effects on probable hydrate formation), and thermal expansion, with the associated interaction with host platform risers.

HIPPS (flowline, pipeline)

This system must be conceived to allow a de-rating of the equipment with relation to wellhead static pressure. The equipment has to be protected in the event of a build-up beyond normal flowing pressures. Architecture of the system has to be defined and tested for performance, in relation mainly to requirements for availability and effectiveness.

In principle, the system may consist of a high integrity control and monitoring unit, a barrier valve and a last-chance relief valve. As a design basis, the general industry standard of multiple sensors in a 2-0-0-3 configuration may be used for inputs and logic. Sensing points should be well separated and the potential common mode problem associated with detection of line blockage should be minimized by design as far as practicable.

A new control fluid has to be formulated. This has to be fully proven in a complete control system, itself designed to operate high pressure, high temperature wells reliably. The effect of adverse conditions such as contamination with foreign matter has to be fully evaluated, along with safety aspects.

Experience on hydraulic control of HP/HT wells is extremely limited. Control fluids previously used are unsuitable for most current field developments, particularly subsea. Studies to date have addressed only the effects of single components and have largely ignored interactions with the remainder of the system and the environment.

Hydraulic components intended for subsea use are specialized and thus differ from both industrial and aerospace equipment. The supply base is narrow, even at pressure ratings of 10,000 psi, and is extremely restricted above that. At pressures above 15,000 psi there is no source of proven technology that covers all aspects of control of an HP/HT reservoir downhole valve.

Similarly, current downhole instrumentation is semiconductor based and is therefore restricted to temperatures below around 180°C. Attempts to introduce optical technology have been made, but no demonstrative tests exist for relevant performance.

Copyright 1997 Oil & Gas Journal. All Rights Reserved.

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