Seabed processing, minimum umbilical systems offer longer tie-back prospects

Aug. 1, 1998
Typical layout for a minimum umbilical remote control system. [103,771 bytes] If all goes to plan, the modular subsea processing system Alpha Prime could be in service on a live field by the end of next year. The technology, which can be configured to include separation on the seabed, is targeted at: Marginal field developments, due to the low capex involved Longer distance satellite tiebacks, avoiding multi phase flow and hydrate formation problems Reactivation of decommissioned fields

Multi-modular system intended for re-use

Jeremy Beckman
Editor, Europe
If all goes to plan, the modular subsea processing system Alpha Prime could be in service on a live field by the end of next year. The technology, which can be configured to include separation on the seabed, is targeted at:
  • Marginal field developments, due to the low capex involved
  • Longer distance satellite tiebacks, avoiding multi phase flow and hydrate formation problems
  • Reactivation of decommissioned fields
  • Late field life retrofit, to defer abandonment of infrastructure replacement of FPSOs in shallow or remote deepwater applications.
Alpha Prime is a modular seabed system, designed for diverless installation and subsequent retrieval for re-use on another field. The system's modules can be configured to suit the requirements of the field using either manifolding or subsea separation. Modules can be inserted and removed without the need to shut in wells, and can also be designed for 100% availability while one system component undergoes maintenance or reconfiguration, brought on by changes in the reservoir's characteristics.

The technology has been developed over several years by London-based Alpha Thames Engineering, but progress has been speeded up of late through the acquisition of the company by Sweden's Kockums Group, which subsequently passed on a 25% equity stake to UK independent oil company Hardy Oil & Gas. Hardy also took on the worldwide license for this technology.

At Alpha Prime's heart is the Aesop all-electrically-powered seabed processing system, the prototype for which has been sponsored by a joint team including Conoco, Shell and Statoil, as well as Hardy. A completed version should undergo tests in mid-1999. Other important modules include:

  • HWC, a subsea mateable electrical connector rated up to 11kV and 1MW currently, although a newer version is under development with 22kV capability;
  • REAct, a fail-safe electric valve actuator, ROV operable in remote and deep locations, and also integrated easily with high integrity pressure protection systems. This has already been designed, patented, and certified;
  • MATE, a multiple pipework connector allowing simultaneous connection and disconnection of up to six, 8-in and four, 4-in. flowlines, with both halves of
the connector internally valved to contain process fluids when separated. A version was recently built and then tested at Kockums' site in Malmo last month;
  • CUSP, a tool for tie-in or pull-in of rigid or flexible flowlines, bundles, electro-hydraulic umbilicals, plus valve retrieval and pipeline repairs. This can be operated from a surface vessel or an ROV. Again, testing has been completed at Malmo, with certification already granted by DNV.
The prime mover, however, will be Hardy, which has ambitions for the technology extending beyond its own field interests - although one of these, the PY-3 Field, was considered as the first application. PY-3 lies in deep waters 10 miles offshore India. Detailed studies were conducted of a production application using Alpha Prime, but in the event, the partners fulfilled an earlier commitment to an FPSO.

Hardy was sufficiently impressed, however, to acquire the licence rights and then form a subsea venture to promote the technology with Halliburton Energy Development and Brown & Root Energy Services. Hardy believes Alpha Prime can enhance its appeal as a potential field partner, particularly on fields considered marginal using conventional development solutions. According to Joe Woolf (a Hardy technical manager at the time of this interview), the technology can cut typical development capex by $2/bbl.

In cases where Hardy is the field development operator, Brown & Root would normally be the lead contractor.


For some time prior to these transactions, Hardy had been evaluating all types of technologies coming to fruition on all aspects of drilling, facilities and subsurface engineering, Woolf said. "We plotted potential for added value and technical risks of these techniques, and also their fit with our applications."

Initially, Hardy identified multiphase pumping as being the most interesting, joining an industry research project with Petrobras and Westinghouse. Then came the involvement with Aesop. "Through that, we understood better the risks of subsea separation. In fact, owing to the advances we saw, these risks were not as great as we had feared."

Woolf believed that subsea separation also offered many advantages over conventional solutions for less mature deepwater regions. Among these are the fact that a dedicated well intervention vessel is not required, nor offshore loading - a point which should appeal to MMS in the Gulf of Mexico.

The technology's low operating costs also help the operator extract more from the reservoir over a longer period. There is no pressure to keep production levels high over five years - as with a leased FPSO - in order to maximize the investment. Instead, the seabed separation system can be kept running steadily for, say, 10 years.

Then when the time comes to abandon the field, the equipment, being modular, can be retrieved quietly from the seabed without supply boats or helicopters in attendance.

Weights and sizes of the modules have been limited to 100 tons maximum to facilitate handling by conventional diverless systems. However, 10 years from now, diverless techniques may extend to 1,000-ton operations - "in which case, you could go for full processing, rather than just separation," Woolf said.

Production capacity is not constricted. Through use of multiple Alpha Primes with clustered wells on the same fields, multiples of 30,000 b/d production systems could be achieved. And while conventional 20 km subsea tiebacks to fixed installations could be attained easily, "being all-electric, there's no reason why in the future we couldn't do it for 100 km," Woolf added.

This might suit certain operators of deepwater discoveries offshore West Africa, he claimed, who could not justify a dedicated FPSO, but could use Alpha Prime to tie their fields back a long way to existing installations in shallower waters. Another advantage in this region would be that subsea separation would avoid the need for measures to counter slugging, wax or hydrates formation - it would simply remove the problem at the wellhead.

Brazil is seen as another potential market. Other contenders are the Caspian Sea, where there is currently a constraint on supplying full-scale fixed or floating installations due to the land-locked situation. Another candidate farther in the future could be the normally iced-in regions of the Barents Sea, where fixed platforms are probably to be avoided.

The next step for Hardy is to prove Alpha Prime on a live field installation. A longer-term aim is to progress the processing to handle problematic hydrocarbons, for instance with high hydrogen sulfide or carbon monoxide content.

MURCS under test

Last month, another new subsea system suited for marginal fields was demonstrated for the first time at British Gas' British Auckland test site in northern England. MURCS (minimum umbilical remote control systems) is a subsea power generation and well control system designed partly to minimize requirements for umbilicals, which are seen as one of the higher cost components of very long distance well tiebacks.

The $1.6 million project, conducted by Caltec in the UK with European Union support, is also sponsored by Amerada Hess, Enterprise Oil, Mobil, and Konsgberg Offshore, with participation from Camco, British Gas, ECS, Honhinco and W.D. Loth.

MURCS is not limited by water depths or offset. The subsea production/injection system is linked to surface facilities via a standard telecommunications fiber optic umbilical and, optionally, by a small-diameter chemical injection conduit piggy-backed to a flowline. This conduit should cater for increased chemical demands as subsea processing systems become proven.

The project team took into account the likelihood that total severance of subsea control from the surface will not be practicable for a while yet. But umbilical size and cost can be restrained by dedicating it to vital telemetry and chemical supply functions.

MURCS supports this objective in two ways - control system power requirements are provided by a local power supply driven by produced fluids, and hydraulic needs are furnished by untreated seawater. A local power supply needs to be robust, with a significant amount of power (electric and hydraulic) available rapidly to support multiple re-starts. There must also be a contingency method for recharging faced with successive shutdowns in quick succession.

Use of seawater hydraulics helps bring down overall costs. Actuated components are simple, relatively inexpensive, and mimic operating characteristics of conventional units. Direct acting pilot valves consume more power than the multi-stage units in conventional electrohydraulic systems, but they also eliminate the need for costly, clean hydraulic practices.

System components

There are four major components in the MURCS subsea power supply system - a gas expander power generator, generator controls, fluid conditioning and pressure recovery, and energy storage. Capacity must be sufficient to optimize operational flexibility without risking production security, should problems occur on the surface host facility. Excessive capacity would threaten production also through elevating system back-pressure.

Mobil's prototype 15kW gas expander was made available for the demonstration system. This is an adaptation of submersible motor-driven pump sets already used offshore for seawater lift and firefighting. These machines typically feature a multi-stage pump driven by a direct coupled, water-filled and cooled injection motor.

For this prototype, the induction generator runs continuously at full load, with an ECS-designed power control system switching in and out dump loads to balance the load on the generator.

A PLC can also be used to monitor parameters such as current, bearing temperatures, and oil and vibration levels. The generator produces a three-phase alternating current, but this can be reconfigured according to the subsea control system's demands.

The processing equipment for use with MURCS is an adaptation of Caltec's Wellcom well commingling system. Portional flow from one well is routed to the power supply. Caltec's Wellsep compact in-line separator is also applied to remove most of the entrained solids and about 20% of the diverted flow will carry the removed solids through a bypass line. This flow is then recommingled with discharge from the expander, and subsequently combined with the balance of flow from the supply well, using a jet pump.

Energy storage is tailored according to re-start requirements, which must take into account anticipated surface shut-downs. Primary energy storage is electrical, much of it being used to re-open valves and start production so that power can then be generated for ongoing applications.

The seawater hydraulics comprises a linear gate valve actuator, a stepping choke actuator and a seawater pump. Unfiltered seawater is used as a power fluid for the open loop hydraulic control system. The pump takes suction through a coarse screen from the surrounding sea. Seawater is then pressurized and pumped to the valve actuators via the pilot valves, and return seawater is dumped back into the sea. Nominal operating pressure is 24 bar, with a flow rate of 50 liters/in.

Wellsep will also be demonstrated alongside MURCS at open days at Bishop Auckland in September 3 and October 1. During a trial earlier this year at British Gas' Lower Thornley test site, gas flows of up to 8 Mcf/min were passed through a 4-in. Wellsep with sand feed rates of around 10g/min. The system managed to remove 98% by weight using a purge gas flow of 20%, and over 95% by weight with a purge flow of 10%. Further trials are planned, including separation of solids from a wet gas stream and separation of solids from a liquid stream.

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