The world's first large-scale, subsea cent-rifugal compressor module could enter service late this decade on Norway's Ormen Lange project.
Four high-profile operators have provided funding for a proposed 12-MW system under a four-phase program. GE Oil and Gas, Nuovo Pignone, and Aker Kværner, which have jointly evolved the concept since 1992, are performing technical studies. Two years ago, they introduced their first 2.5-MW prototype, incorporating a GE Blue-C compressor, at ONS in Stavanger.
During the 1990s, there were concerns that some marginal subsea gas fields could not be developed, due to high associated platform modification costs. This inspired a series of remote seabed processing/production studies, some of which remain on the drawing board. Nuovo Pignone and Kværner Eureka, as the latter was known in 1992, were among the early pioneers, developing an 850-KW subsea compression prototype comprising a variable-speed electric motor, planetary gearbox, and centrifugal compressor. This was configured in a vertical arrangement, a first for the industry, according to GE Nuovo Pignone Chairman Piero Salvadori.
Although activity was then suspended for six years, due to a surprising lack of operator interest, the project was revived in 1999 through funding from Norway's Demo 2000 R&D program, led by Statoil, Norsk Hydro, and the government.
The money was used to remove the 850-KW module from storage, refurbish the compressor with new components, and mount a new series of more extensive trials with more advanced test equipment. This time, the unit underwent 600 hours of endurance tests in Florence. Under the Demo 2000 remit, the partners also designed a larger system, using parameters supplied by Hydro and Statoil.
Progress on the resumed project was outlined by GE Oil & Gas authors in a paper at last year's Offshore Mediterranean Conference in Ravenna, Italy. They foresaw two basic process scenarios. For applications involving gas-dominant fields, the well stream would be sent directly to the subsea compression module. However, if liquids predominated, gas would first be stripped out through a separator situated at the wellhead.
To eliminate the liquid completely, the mixture entering the module would be conveyed initially to a cooler and then to a three-phase scrubber. From there, the liquid would head to the host platform via a multiphase or single-phase pump. Gas would meanwhile be sent to the compressor suction flange for compression.
The subsea compressor (as of April 2003) is based on a standard barrel-type design, with two flanges (one for suction, one for discharge), and in the case of the 2.5-MW prototype, with six in-line stages. The vertical system comprises one static unit (casing, casing heads, covers, diaphragms, seals, bearings) and one rotating unit, the rotor being formed by a shaft, impellers, and a balance drum on the discharge side. The back chamber of this drum, as is normal for centrifugal compressors, is connected to the suction chamber through the balancing line to ensue equal pressure at both ends of the line.
The module's rotating components are each lubricated by oil, with power being transmitted to the oil pump from the electric motor through a gearbox wheel. All three main casings – centrifugal compressor, gearbox, and electric motor – are joined together with screws. The choice of an epicyclic, planetary gearbox allows perfect axial alignment of the electric motor, gearbox and centrifugal compressor shafts, and also enables the three casings to be connected together with the minimum footprint.
Prototype of the centrifugal subsea compression module.
According to the authors, proven, reliable components are essential to maintain safe lateral behavior and low vibration levels, in turn minimizing the possibility of seal damage. To this end, stiffness of the rotor has been maximized. The impellers are of the type used widely in re-injection applications, with a maximized bore diameter.
The centrifugal compressor meets API 617 requirements: its inlet design flow is 900 cu m/hr, with suction pressure of 65 bar and delivery pressure of 130 bar.
Gas employed in tests to date has been methane with a molecular weight of around 18. Casing design pressure is around 200 bar. Compressor design conditions (pressures and temperatures) have been selected to compensate for wellhead pressure decrease over time, while maintaining constant gas production during wellhead life.
All the subsea module's components are pressurized at the compressor's suction pressure. Buffered end labyrinth seals have been fitted on both sides of the compressor shaft to prevent flow of oil between the journal bearings and the processed gas. Small quantities of this gas are reduced in pressure and conveyed to the mid-point of the seal. The barrier this creates between the processed gas and oil-bearing side further minimizes oil consumption, considered critical in this project. The oil tank is filled during the module's commissioning phase, but no re-filling is permitted during actual operations. Higher than anticipated oil use could affect maintenance schedules, in turn impacting the field's productivity.
Differential pressure between buffer gas and suction pressure can be held down to 0.2 bar to lessen buffer gas consumption, thereby increasing the compressor's efficiency. Oil is then collected from the journal and thrust bearings for conveyance to a pressurized tank at the end of the compressor. The tank's pressure is equal to the compressor's suction pressure, so there is no need for dry gas mechanical seals. Simplifying the machine's architecture in this way allows maintenance intervals to be lengthened, and should also extend the rotor bearings' life span, the authors claim.
As for materials, the system is designed in its present form to handle sweet gas, but the presence of CO2 would call for greater use of corrosion-resistant steel. Presently, all the compressor's static components are made from stainless steel, as during shut-down periods, the presence of water around the compressor casing might well lead to a build-up of free liquid water inside the gas. Impellers must also be CO2 and water-resistant.
One of the main differences between the subsea compressor and conventional topside systems is the exchange of heat between the process gas and the external cold seawater. The effect of this exchange must be analyzed correctly during the design phase to avoid mismatching between the stages during actual production (caused by the suction temperature at the lower stages). In practice, gas exiting one stage should be cooled before entering the next stage.
Upstream of the compressor flange is a gas liquid separator followed by a cyclone scrubber, the purpose being to protect the compression module against liquid ingress. Gas-drying requirements should be identical to those of land-based compressor applications. The anti-surge system comprises a top-entry, metal-seated subsea control ball valve, with hydraulically operated, rack-and-pinion type actuator. Both are in direct contact with the surrounding seawater. However, those parts of the subsea control system that are more prone to failure (the servo-valves, shuttle, and isolation valves) are enclosed in a pressure-compensated subsea pod.
During 2002, the partners put the refurbished 850-KW compressor module through a series of trials at the Nuovo Pignone headquarters in Florence, Italy, in a water-filled tank with process gas loop. The program comprised an API 617 mechanical running test, and ASME PTC10 type 1 test and a 500-hr endurance test, this time using natural gas as the flow medium. In each case, process conditions were carefully reproduced, e.g., flow, temperature, pressure, machine speeds, and power consumption. According to the authors, this program provided a near-complete analysis of the entire module's thermodynamic and mechanical behavior, including compressor performance curves, surge limit, and machinery vibrations in both transient and steady-state conditions.
Subsequent review showed that the machines' mechanical behavior complied with requirements. In particular, the rotors' vibration level was low and in accordance with API specifications. Auxiliary systems also performed as expected under all operating conditions. The improved seal system reduced lube oil consumption to almost zero, and increased efficiency of the unit by 3%.
These findings were then used as the basis for a 2.5-MW design using Nuovo Pignone's Blue-C compressor, discharging gas at up to 130 bar, with suction pressure of 65 bar, and 70% efficiency (similar to conventional topsides compressors). The efficiency of the machine is normally higher with respect to similar topsides applications due to the positive effect of external water cooling. A preliminary design for a 5 MW unit was also completed.
Last July, GE Oil and Gas and Aker Kværner signed a cooperation agreement to continue development, testing, and qualification of subsea compressor technology through 2009. Under a new four-phase, pilot project sponsored by Norsk Hydro, Shell, Statoil, and Total, they intend to qualify a system in real subsea conditions. According to GE Oil & Gas Centrifugal Compressor Product Leader Leonardo Baldassare, the first-phase feasibility study has been completed: "The field has been identified, as well as the general architecture of the subsea layout. Now we have started conceptual design at the components level, i.e. machinery, separators, and so on."
The new aim is to produce a 12.5-MW subsea module that could be applied to develop deepwater gas fields directly from the shore (as would be the case at Ormen Lange), as well as from offshore platforms.
"We are looking to new technologies that can simplify the module architecture and increase the efficiency and reliability of the train by means of an oil-free solution – a high-speed electric motor drive and magnetic bearings – instead of the conventional oil bearings/low-speed motor and gearbox combination," Baldassare said. "Even though this solution looks attractive from the point of view of system simplification, intensive investigations are needed to prove that the module has the required reliability. We must also evaluate whether it is feasible to make all the power equipment operable in a subsea environment."
One potential problem is the constraint on power imposed by the electric motor cooling system. Another important consideration is the module's architecture and packaging, which must allow for straightforward lifting, installation and subsequent extraction from the seabed for inspection purposes.
Charts show performance curves of the refurbished 850-KW subsea compressor during trials completed in Florence in 2002.
Until early 2002, the partners had planned to run preliminary tests of a module on a North Sea platform, assumed to be Norsk Hydro's Troll C semisubmersible. Now, however, following qualification trials planned in an onshore tank, the first prototype will be tested directly on the seabed at Ormen Lange, where it will operate for around 18 months. "These tests will have to demonstrate that subsea compression is feasible, reliable, and profitable," says Baldassare. Ormen Lange is due onstream in 2007, although compression is not expected till around 2016, according to London-based field analysts Scanboss.
The estimated development cost is $30 million. The 12-MW compressor will handle up to 25 MMcmd of gas, with a suction pressure from 45 bar-a to 130 bar-a, and a delivery pressure of 12-140 bar. Changes will occur over the years according to the wellhead pressure profile. Although this system will incorporate a separator for dry gas operations, a wet gas compressor will also be developed that can handle up to 15% water content in the gas stream.
Talks are also continuing with a range of operators over potential gas-boosting or gas re-injection applications elsewhere in the North Sea, Gulf of Mexico, Brazil, and Angola.