Evolution of subsea compression technology.
Deepwater projects are being developed today to reach depths as great as 3,000 meters with floating production units (FPU), floating production storage offloading (FPSO) and tension leg platforms (TLP). Advances in subsea development could make the development and production of marginal fields more attractive.
Technology is emerging that offers the possibility of eliminating the topside facilities, then locating the receiving facilities in easier environments either offshore or even onshore, transferring the production through subsea pipelines. Subsea processing will allow separation of liquids, water and gas. Downstream of the separator, single-phase pumping is then possible and, as a consequence, subsea gas compression is required. Obviously, the particular installation site leads to specific technologies and innovative design solutions.
Subsea Technology Path
The North Sea sector has long been the most active promoter of subsea developments. The oil and gas industry has invested heavily in new technologies to push forward the limits of subsea developments. The first machines to be used to pump the fluids were the multiphase pumps introduced some decades ago. The development of seabed processing allows compression of single-phase fluid and then requires gas compression. Nuovo Pignone (now part of GE Oil & Gas) in 1985 started the development of multiphase pumps with the following design goals:
* Handle untreated well fluid (a mixture of crude oil, water, gas),
* Reach high reliability and availability (minimum two years maintenance-free operation for subsea installation).
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The SBS Project (with Agip, Saipem, Snamprogetti) was conducted to evaluate different technologies and qualify and test the most appropriate. Main equipment included twin screw, diaphragm and centrifugal pumps. Hydrobooster components were also part of the program: pump mechanical seals, elastomers for diaphragms, electric power connectors, electric motor power penetrators and optical fibers.
After development/prototype tests were carried out between 1985 and 1988, the twinscrew pump technology was selected for multiphase boosting in subsea installations as the optimized configuration to meet critical process requirements (flow, differential pressure, GVF etc.) in terms of size, weight and easier subsea installation. A product qualification program was then carried out, including installation of demonstration units to perform extensive endurance tests.
The first development was started in 1988 with the MP 10 model: 150 kW, 70 m3/h,
3,000 rpm, 40 bar DP, 90% gas volume fraction (GVF). Between 1988 and 1989, the machine accumulated 7,600 hours.
The NPV 70 subsea development project using MP10 was carried out in 1992. This first pilot subsea project was located in the Prezioso oil field off south Sicily and represents significant subsea operation experience, with the machine operating for 7,600 hours over nearly 2.5 years.
At the same time, the NPV 280 was developed, with the following specifications: 450 kW, 280 m3/h, 3,000 rpm, 45 bar-a DE 95% GVE Next came the PSP 114/54 with the following specifications: 400 kW, 150 m3/h, 1,200 rpm, 40 bar DP, 95% GVF, high viscosity test (4,500 cSt). This machine was installed in the AGIP Gela field.
Between 1999 and 2004 a larger size was designed. It is the NPVI600, which offers 2.5 MW, 800 m3/h, 1,800 rpm, 70 bar DP, 95% GVE Validation tests were successfully performed at GE's Oil & Gas Florence test site (Figure 1).
The general system concept is the following:
* Vertical configuration.
* Twin counter rotating screws.
* Electric motor.
* The system is totally pressure balanced at the process pump inlet conditions.
Main characteristics of the technology adopted:
* Oil tank acts as the baseplate for the pump and motor;
* Pump unit casing is designed to withstand the environmental conditions and pressures of the application scenario;
* Screws and shafts of "integral" design, i.e. machined from a single forging, providing much higher pressure, viscosity and shaft torque capacity;
* Carbon steel, stainless steel or duplex steel selected for the screws and the liner, taking into account the specific corrosive components of the fluid;
* Hardening treatment in case of the presence of abrasive fluids; and
* Screw pump with four hydrodynamic journal bearings, and two hydrodynamic thrust bearings, heavy-duty type, lubricated by the forced lubrication system.
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Electrical Power Chain
The subsea pilot provided the opportunity not only to develop the pumping package but also the complete electrical power supply. The system includes: the subsea electric motor, the underwater wet mateable power connector, the power cable within the umbilical and the dedicated topside electrical equipment.
To drive the motor, a variable frequency drive converter was used for installation topside. Modem converter technology provided frequency converters for output voltage from 1,000 to 6,600 VAC. The waveform was sinusoidal, with low pulse width modulation content. This gives the motor steady output torque with low harmonics. These converters can feed medium voltage motors directly without using transformers, resulting in a new range of step out distances. To link the two systems, umbilicals with three core cables for distribution voltages up to 100 kV are used. The high voltage power cable can also be integrated into the umbilical together with optic fiber bundles and duplicated auxiliary (LV) power supply cores.
From the positive results achieved within the different projects mentioned, GE Oil & Gas has shown the capability to provide production and transportation multiphase systems.
As seabed processing moved forward, the need for larger machines to handle large flows emerged. Centrifugal compressors are therefore the most suitable technology to provide large power units with compact and reliable solutions. In 1992, the first machine developed was an 850kW prototype subsea compression unit (Figure 2). The unit was tested in a water-filled tank in GE's Oil & Gas Florence plant and in Norway. Approximately 200 hours were accumulated.
In 2000, the Norwegian government financed research of subsea applications via the Demo 2000 Program. In 2001, GE Oil & Gas and Aker Kvaemer signed an agreement to develop a subsea gas booster module and joined the Demo 2000 Project. The objective of the Demo 2000 Project was to prove the feasibility of subsea compression, starting with a small power prototype then developing new high power compression modules with the same architecture, using proven components based on the test findings. The main areas of focus for obvious reasons, given the subsea environment, were:
* Reliability, with a target minimum of three years between any kind of intervention;
* No failure;
* No oil consumption and environmental impact;
* No leakage into the environment; and
* No risk in case of major component failure.
A rigorous qualification process was followed with complete onshore testing of all equipment in a water-filled tank (done for the 850-kW unit), complete offshore testing and, finally, an endurance test in seabed conditions (300-400 meter depth) to prove the concept and to demonstrate profitability.
As part of the same program, a 2.5-MW subsea module conceptual design was launched in 2002. Then, starting in 2003, a gas booster qualification project (12 MW) was launched and is still progressing. Norsk Hydro and its partners have decided to move forward on the pilot phase for Ormen Lange field development.
Working with Aker Kvaemer, GE Oil & Gas has completed the conceptual design of a 12-MW subsea compressor, the Blue-C[TM], the largest ever developed for subsea applications, and is set to begin construction of the machine to be tested in the pilot project (Figure 3 and Figure 4).
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The aim of the pilot project is to evaluate whether a subsea compression station, at approximately 900 meters water depth, is a viable alternative to an offshore platform. The project represents a major milestone in the development of subsea compression technology. If the project produces the expected results, the Ormen Lange partners will have a cost-effective alternative to the originally planned offshore platform. This technology then could be applied to other subsea field developments, eliminating the need for offshore platforms.
Subject to the Ormen Lange partners' final approval, Aker Kvaerner's subsea compression station pilot project will undergo controlled endurance tests from 2009-2011 at a gas treatment facility in Nyhamna, Norway.
Facilities can be located onshore or offshore. An umbilical is used for power and utilities distribution. The main subsea equipment includes transformers, frequency converters (for electric motors only), valves and flow lines.
The gas booster module includes an upstream gas treatment unit, a cooler and a gas scrubber, a gas compression unit (including lube oil system, if present), a downstream cooler, scrubbers for seal gas conditioning and single or multiphase pumping unit, if required.
The first generation of Blue-C centrifugal compressor was driven by a variable low speed electric motor. A planetary gear box gives the speed ratio. The lube oil system was common to the gear/compressor. A buffer gas system was required for the compressor as well as a cooling system for the electric motor. The main features of the machinery were:
* The casings connected by screws and pressurized at compressor suction pressure.
* No gas released into the environment, because no differential pressure on the compressor shaft ends, therefore no dry gas seals were needed.
* In addition, the compressor shaft ends were equipped with special buffered labyrinths to avoid oil migration.
The compressor is a BAL (barrel multistage centrifugal) type, vertically arranged. The compressor architecture (stages, bearings, seals) is standard and well proven. The compressor selection is customized using stages from the company's standard stage database to match different process requirements. The rotor stiffness is maximized to increase the reliability. The materials are selected to ensure resistance to carbon dioxide general corrosion (stainless steel) as the present produced gas is "sweet."
The Blue-C prototype was extensively tested to confirm the thermodynamic and mechanical behavior, and also underwent an endurance test of 500 hours. To reproduce the ambient conditions, the equipment was installed in a tank (Figure 5). The test was performed according to SAME PAC type 1 test requirements, which closely approximate real conditions and confirmed even better the predicted performances.
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Ormen Lange is the first example of a new generation of large compressor units. New technologies that have been proven for onshore applications enable the design of more reliable and compact units, as most of the auxiliary systems can be reduced or avoided. Two examples that offer the possibility to define new train architectures are:
* Active magnetic bearings installed inside the process gas allow the elimination of lubrication systems.
* High- speed induction motors have demonstrated the suitability for speeds above 6,000 rpm to meet the optimum speed for the design of centrifugal compressors, eliminating the need for a gear box and providing the full benefit of an oil-free configuration.
New technologies and solutions are leading the increase of activities on the seabed. It is a tough challenge as the expectations are always more ambitious but continuing advancements in technology can lead to significant breakthroughs in the years to come.
Pierre Laboube is marketing products leader and centrifugal compressors product leader for GE Oil & Gas-Thermodyn, based in Le Creusot, France. He is an engineering graduate of the Eeole National des Arts et Metiers. After serving as a professor at Bath University in the UK, he joined Thermodyn where he held several positions as application engineer, project manager, scheduling leader and application department manager. In 2004, he was appointed centrifugal compressors product leader covering, also, Thermodyn products marketing. Since April 2007, he has served as new product introduction leader within the GE Oil & Gas Engineering Management Team.
By Pierre Laboube, GE Oil & Gas-Thermodyn, Le Creusot, France
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|Publication:||Pipeline & Gas Journal|
|Date:||Nov 1, 2007|
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