Modularized subsea processing technology developed in the United Kingdom is heading for its first field trial and could significantly enhance the toolbox available for subsea tiebacks.

Ian Ball, head of Shell's subsea-to-beach technology development program, revealed that the Alpha Prime system, developed by Alpha Thames, has recently passed through a series of qualification tests to satisfy the oil major. It is ready for a first field trial.
The Shell program manager has indicated that Alpha Prime might debut on a deepwater Shell development in the Gulf of Mexico in order to assess its commercial application.

"There are several possible deployment opportunities, in deepwater in particular, for this technology to be able to improve the economics of a field development quite substantially," Ball said.

While the potential benefit from subsea processing varies from field to field, Ball suggested this particular technology could increase recovery significantly in favorable reservoirs "... accelerating production quite significantly and giving [production] rates that are substantially higher than they would be without this boosting capability."

Ball said Shell has a short list of potential fields which might benefit from the modular system.
"We have been pretty pleased with the way the component qualification has gone," he said.
"We have tested the key components to a point where we are confident that they are ready for a first deployment with additional testing in the field. The next stage will be a field pilot of the Alpha Thames system and that is always the most difficult part of this deployment process. It is finding the right asset to have this system installed in a field."

Ball said there has been a strong willingness within Shell to test the technology by selecting the right field for a test, "But we are not there yet," he said.

However, he confirmed a deepwater Gulf of Mexico field is among the options. "We are definitely including the Gulf of Mexico in our global portfolio scan," Ball said.

"We clearly feel that subsea processing offers major benefits the deeper the offshore field, so we are keen to test it with a relatively deepwater well, that is something in the region of 500 m (1,640 ft) and deeper. That is where we have hubs in the Gulf of Mexico."

As to the timing of the trial, Ball added, "We have already formed a project team to evaluate pilot options and progress to implementation. We are finding a lot of co-operation from potentially suitable assets." He said a lot of Shell asset managers readily appreciate the longer-term value of the technology.

Shell's subsea to beach technology development program has been running for 3½ years, managed by Shell's International Exploration and Production (SIEP) division within a group research and development project framework.

Alpha Prime is essentially an all-electric incremental field development solution for control and processing hydrocarbons in water depths down to 10,000 ft (3,000 m).

David Appleford, managing director of Alpha Thames who has been promoting the technology for nearly two decades, said this is the first big breakthrough for the modularized subsea processing system which is scalable, reconfigurable and can be enhanced without production shutdowns.

Qualification tests were conducted in Kent and Newcastle in the United Kingdom, and in Malmo, Sweden, at facilities operated by Saab Technologies under supervision by Det Norske Veritas. If and when the system passes a Shell field trial, it could become readily selectable for use in other Shell projects.
The central processing system known as an Alpha CPU comprises a dumb Keyman manifold fitted with remotely operated vehicle (ROV)-operated gate valves. This can be placed on the seabed by attaching to a suitable pile typically via a 30-in. industry standard casing connection, or using gravity based suction piles or mud skirts. A number of plug-and-play processing modules are attached on to this via standard wellhead type hubs (typically 213/8 in.) with up to five well bores. The modules are configured to suit the reservoir characteristics of the field on which they are installed. The system can thus provide boosting and/or two- or three-phase processing using either gravity or compact hydro cyclone separation.

It takes typically up to 24 hours to replace one of the process modules supported by ROV. The modules - which feature wet-mateable connectors for both electrical power and electronic control/monitoring interfaces - can be engineered to offer a variety of services for a subsea well, from artificial boosting, to multiphase pumping, gas flood or water injection.

"Maintenance is not the only reason you are going to change one of the modules," Appleford said. " The operator now has the ability to change the seabed facilities to suit whatever field depletion characteristics are experienced at any time through the field life.

"There is no minimum and maximum size for these modules," Appleford said. "It does not matter. We can make them any convenient size. You can, therefore, design a module to suit the throughput requirements of a field."

He suggested a 45,000 b/d fluid-processing module is typically possible, while a two-module system could provide 90,000 b/d of fluids processing.

The only limit is the acceptable weight of the modules themselves, which are typically 80 to 100 tonnes to allow for installation without requiring a heavy lift barge or crane vessel.

One of the features of the design is failsafe electrical valve actuators, which at the end of April had completed 290 fail-safe tests satisfactorily. Another feature is high-speed control valve electric actuators, which have completed over a million actuations to date. Nitrogen gas-filled high voltage power connectors are also used, which allow any particle contaminants to fall to the bottom of a connection chamber, eliminating the risk of insulation damage and potential connection failure.

System modules measure typically 16.4 ft by 13.1 ft (5 m by 4 m) although Appleford said they have recently worked on a larger, 23 ft by 16. 4 ft (7 m by 5 m) module with 175,000 b/d of fluid throughput with two-phase separation.

To date, more than 15 years and US $25 million has been spent developing Alpha Prime. Over the years support has come from Ultramar, Deminex, Clyde, Hardy, Statoil, Conoco, Shell, the UK's Department of Trade and Industry and the European Union, and also Kokums of Sweden - part of Saab Aerospace - which is 40% owned by BAE. Accordingly, Alpha Thames is currently owned by Saab Aerospace.
At one stage the former UK independent Hardy Oil and Gas was considering buying assets on which to conduct prototype trials of system modules, but it was subsequently taken over by British Borneo - which was later bought by Eni.

Now that Shell has taken onboard the technology, Appleford is clearly keen to see his concept successfully complete a pilot test. And if that happens, then it could soon be primetime for Alpha Prime.

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