UK Deepsep project shifts to producing field trials
- Schematic shows typical production fonfiguration for the Deepsep processing/seperation system.[20,693 bytes]
- Prototype sand handling module configuration - elevation. [86,339 bytes]
The system, know as Deepsep, uses separation and conventional pumps to boost production,. Project leaders MAI Consultants and Tecnomare UK see application in marginal deepwater fields in the Campos Basin and west of Shetland, which are typically hampered by low reservoir drive, in turn requiring pressure boosting for production to reach surface facilities.
Numerous oil companies have supported feasibility studies which to date have proven Deepsep's benefits and identified necessary modules and capabilities. The recent pre-engineering phase examined components needed to adapt the system for a wider range of fields. Now the aim is to test these components in a drydock, with the financial support of Conoco UK, Elf, JNOC, Brasoil UK, SOCAR and UK government organizations. Modules for the prototype will be developed by British companies GEC Marconi Oil & Gas, Babcock Energy, ICI Tracerco and ABB Kent Introl.
Deepsep comprises several modules that would be installed and retrieved from the seabed, close to the wellhead, using diverless and guidelineless methods. Depending on the field, facilities could be added to counteract common problems such as sand production, hydrate and wax deposition Hydrocarbons production is routed via a sand removal and clean-up module to a separator where gas and liquids are separated.
Operation conceptAccording to a recent article in Britain's Offshore Supplies Office's Offshore Research Focus, the system works as follows:
"Gas-free flows back to the host facilities while liquids are pumped using conventional fixed-speed single phase pumps. Control of the separation and pumping modules is via a subsea control pod which incorporates triple redundancy and is totally autonomous from the host facility. Electrical power, injection chemicals and remote monitoring of the control systems is generally supplied via an umbilical, although a buoy system could be used in more remote areas.
"One of the major concerns with subsea systems is the cost involved in inspecting and maintaining equipment. All modules are connected to the base piping module via multiport connectors which means that modules can be retrieved to the surface for repair or replacement without requiring a complete production shutdown."
Another benefit of the subsea separator is its ability to reduce wellhead flowing pressure, permitting higher initial production rates, greater recovery, and quicker recovery periods. The quickfire revenue generated should more than offset the costs of the subsea equipment. Deepsep's partners claim the rate of return would be 10% higher than competing systems.
In a paper delivered at OTC '95 by MAI and Tecnomare, the authors suggested that the final test of the prototype would be based on a single well located 18 km from an existing facility in 520 meters of water. The targeted availability for the single separator configuration in these tests would be 96% or higher.
In terms of maintenance, the base piping module would be the most critical and the only one for which failure would necessitate production shutdowns. But this module would contain only passive equipment to ensure a very high mean time to failure (100 years, according to the paper).
Of the key equipment items, the sand handling module incorporates solid/liquid cyclones to remove sand particles from the wellstream fluids. These cyclones are situated in the top of a pressure vessel, where a pre-determined amount of sand is allowed to accumulate, monitored via nucleonic level detection.
A second set of cyclones impart high shear forces to dislodge oil from the sand, which is then circulated using a fluidizing cyclone in the storage vessel base. Fluidization is provided by high pressure water discharged by the production pumps. This same cyclone then transfers the sifted sand to a point well away from the Deepsep for discharge to the seabed.
The separator, operable in two or three-phase mode, again uses nucleonic level detection to determine gas-oil and oil-water interfaces. This system is also placed on the seabed, close to the wellhead,
theoretically offering greater stability than a separator housed on a floating production system. It would also be able to handle higher wellhead flowing temperatures, in turn resulting in lower oil viscosity and a lower risk of emulsion formation, thereby aiding separation efficiency. No risers would be required upstream of the separator.
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