Renewable energy developments and climate initiatives are testing the ingenuity of offshore oil and gas service groups. Baker Hughes sees wide-ranging scope for adaptations of its subsea products in particular, as various engineering managers revealed during a subsea session at the company’s Annual Meeting 2021 earlier this year.
Julian Tucker, Front End Regional Lead for Europe, Middle East and Africa, spoke of the subsea equipment needed to advance carbon capture and storage (CCS) projects. Norway has two long-established programs at the offshore Sleipner and Snøhvit fields, and the government recently approved a third, Northern Lights. This and others under review in the UK involve capture of CO2 from flue gases generated by industrial emitters, subsequently transported via a subsea pipeline or on vessels for injection into depleted oil and gas reservoirs of saline aquifers. “These offshore locations are prime candidates for CO2 stores, given their proven capability in trapping fluids underground, and also, they lie in mature basins that have been comprehensively explored and appraised…The North Sea in particular is poised to become a major arena for CO2 storage.”
Baker Hughes, Tucker said, can provide technologies across the CCS value stream for the capture process; compression equipment for transportation and reinjection; chemicals to mitigate the risk of corrosion; and long experience in drilling and well construction services, subsea systems, and life-of-field monitoring to assist subsurface storage.
He identified three main considerations for CO2 injection systems. 1) The phase behavior of CO2 and the impact this can have, 2) the corrosive potential of CO2, and 3c) issues associated with long step-out distances to the offshore location, as is the case between Hammerfest and Snøhvit in the Barents Sea. “CO2 is more efficiently trapped in a dense phase and is therefore compressed…and can be in a super-critical state. This impacts materials selection, including solidity effects that can impact performance of polymers, and fracture toughness for crack propagation in pipelines. There is also the potential for very low temperatures in the system as a result of expansion due to pressure drops, and the effect can be significant if associated with a change of phase, for example, from a super-critical fluid to a liquid or gas. So the system must be carefully designed to manage these changes and materials selected and tested for these conditions.”
CO2 is also highly corrosive to steel when water is present, and the level of potential damage ultimately depends on the water content in the process stream. “Again, this can be mitigated through careful materials selection, use of dehydration processes, or through chemical-forming inhibitors…Baker Hughes delivered the world’s first subsea CO2 injection system for dedicated commercial storage at Snøhvit, supplying a record-setting electro-hydraulic subsea control system for the 175-km [109-mi] step out, although it was actually qualified for 220 km [137 mi]. This offset is similar to other planned CCS projects.”
The company is also developing an all-electric system which, through use of electric actuation, negates the need for hydraulic lines in the umbilical. For long offsets, Tucker claimed, the cost saving can be significant. And the company’s flexible pipe products for subsea risers, well jumpers and infield lines include flexibles with a proven capability in CO2-rich environments, assisted by ongoing research into stress corrosion cracking and CO2 gas permeation into the pipe annulus.
“But CO2 injection systems are inherently different to those for hydrocarbon production systems in their operation and defining characteristics, and these in turn are governed by technical and economic drivers. While there is a great opportunity for simplification, there needs to be careful consideration of the CO2 store, the modes of operation, the system design and materials selection to ensure the equipment is fit for purpose. And the industry needs to build on the great strides made in recent years reducing costs and inefficiencies and apply that mind-set to CCS.”
One of Baker Hughes’ higher-profile developments of recent years is its Modular Compact Pump (MCP) for subsea boosting. The multi-year R&D project has support from various majors and Norway’s Demo 2000 program, and is currently on track for qualification to TRL 4 and 5. Senior Product Manager for the development, Jose Plasencia, said the MCP is a strong candidate for removal and reinjection of CO2 from dense gas, which is a pressing concern for Petrobras as it seeks to develop CO2-rich reservoirs in the presalt offshore Brazil. To produce and process the wellstream, Plasencia pointed out, more than half the FPSO topsides would have to be dedicated to CO2, so Petrobras has patented an alternative approach in which the CO2 is separated at the seabed at super-critical conditions. After the CO2 is removed in a separator, a dense gas (CO2) pump is required to provide high-differential pressure, 4-500 bar (5,801-7,252 psi), for reinjection.
“Placing this process on the seabed brings a big simplification to the floating facility, as otherwise, there would be a need for an entire CO2 processing plant topside. At the same time, the hydrocarbon production is massively reducing its CO2 footprint this way. But this subsea system is also complex, and requires a robust subsea pump…”
For all types of subsea boosting applications, the standard MCP building blocks for a four-stage, 1-MW pumping system are integrated permanent magnet motor impellers; a canned motor design; and polycrystalline diamond (PCD) bearings cooled by the process fluid. Each ‘stage’, or individual motor, generates 250 kW of drive power: due to the relatively low load, the pump can operate without the need for barrier fluid, and the MCP is 40% lighter than other subsea boosting alternatives, Plasencia claimed, due to the compact design.
Traditional subsea boosting employs conventional pumps with on one side an electric motor driving a set of impellers on the other side through a rotating shaft. “The MCP is a completely different way of doing boosting. It has integrated impellers in each electric motor. The impeller has permanent magnets attached to its surface, so it really functions as an electric rotor (which allows for the elimination of barrier fluid); and there are no dynamic seals in the hermetically-sealed motor, typically one of the weakest points in conventional pumps. The system can attain differential pressure without facing dynamic issues as there is no rotating shaft. And each impeller is driven by its own electric motor with individual control of speed for performance. The system is also capable of boosting at lower suction pressures... so the MCP really stands out as a candidate for subsea reinjection of CO2.”
The MCP is qualified for boosting of multiphase flow streams, he added, at 25% lower capex cost than other subsea multiphase pumps, and with 50% less topside footprint (due in part to use of a light power umbilical conveying power from the host platform to the system, with the associated equipment occupying less space topside). For CO2 reinjection, the pump system would use most of the MPP’s qualified components from MPP, including wet and dry mating connectors, electric motors, variable-speed drives, and the overall design architecture of the pump.
A prototype has been tested at up to 5,000 rpm at an 80% GVF, with tests confirming the inherent redundancy, operating with a free-spinning impeller. Other tests have been completed on the lubricated bearings, motor and power electronics design. The remaining program includes 1,500 hr of submerged endurance testing at SINTEF’s multiphase flow loop in Trondheim to API and DNV requirements, along with tests of the pump control system components, flow mixer and circulation lines.
“Elimination of the barrier fluid system and the dynamic seal are key in terms of reliability and economics,” Plasencia concluded. And the scalable concept (4-stage, 1 MW to 8-stage, 2 MW, up to 12-stage, 3 MW) covers all different process requirements, he claimed. “Baker Hughes has experience of CO2 reinjection at Tupi and Middle East fields, all of which has been brought into the development of the MCP pump.”
Marius Asak, Product Leader, MECON HV Connectors, spoke of adaptations Baker Hughes is working on for floating offshore wind farms and power-from-shore for more remote oil and gas platforms. The Mecon range of dry and wet-mate HV connectors have been developed for subsea processing, with the first HV wet-mate connector deployed on the Troll Pilot in the North Sea in 1998 (at the time a world first). Since then the technology has been adopted for other projects including the Tyrihans water injection system, the Ormen Lange subsea gas compression pilot, and Åsgard subsea compression, all in the Norwegian Sea.
As Asak explained, “dry-mate connectors are mated above sea level and wet-mate connectors subsea. They are used where there are power consumers or producers that need to be connected/disconnected separately, without having to retrieve a larger system. Today the Mecon dry-mate connectors range from 1-145 kV – Baker Hughes is the sole company to achieve this upper limit, and is confident the voltage could go higher. The wet-mate connectors are currently 1-36 kV, but with plans to scale up to 72 kV, which would be a world first and a key enabler for floating offshore wind.”
The wet-mate connectors are operated using the Baker Hughes horizontal connection system, a lightweight clamp connector. The clamp fits together with the male half while the interface to the ROV is on the female half: when both halves are perfectly aligned, the metal seal is disengaged, and the clamp is then closed, completing the mechanical connection. Preparations for operation involve the ROV first removing the protection cap, installing the stab connector and engaging to four hydraulic lines. A 17-minute flushing process then follows, initially of seawater between the two connector halves in order to remove trapped salt particles, with fresh water used as the flushing medium. The fresh water is then replaced with ethanol, which once dried out, is in turn replaced by a dielectric fluid. During flushing, the process is monitored continuously and once the required quality is achieved, the electrical connection can be performed in a controlled environment.
According to Asak, installed floating wind capacity worldwide is set to grow from a predicted 14 GW in 2030 to 255 GW by 2050, but for this to happen, the associated power systems must be brought to maturity. “Today power transmission represents 25% of the cost of offshore wind, rising to 50% as new projects move farther from shore. It is therefore critical to cut the cost of the power distribution/transmission system.
“Since 2010, the largest wind turbines operating have risen from on average 3 MW to 13 MW today, with typical voltage ratings up from 33 to 66 kV. For large wind farms far from shore, a transformer will be needed to step up voltage for efficient transmission. So how do you connect the turbines together? They are currently connected in series via 66-kV dynamic cables in a string arrangement. But the cost is high, and if one turbine or cable fails, the whole string connected downstream goes with it.”
Baker Hughes’ proposed solution, with support from various partners and research institutions, is to develop and demonstrate a subsea HV junction box that will connect to the dynamic cable from one turbine, with a static cable installed on the seabed. The J-box concept, he claimed, “provides more flexibility, both on the system and configuration levels, with various turbines still able to operate in the case of an isolated failure. The junction box with wet-mate connector also allows a simple disconnect and retrieval, in case of failure. Since the dynamic cable only needs to transmit power from one wind turbine to the junction box, this will allow the entire wind farm to standardize on a single, small-size dynamic cable. The JV also requires development of a 66-kV wet-mate connector, as none are on the market today.
Another concept under investigation involves replacing the topside substation with a subsea substation, used to connect power from multiple wind turbines, to stabilize and maximize the voltage for transmission back to shore. “The voltage can be collected at 33 or 66 kV, and transmitted to 132 or even 220 kV. The subsea substation doesn’t have to be dimensioned for harsh subsea/weather conditions. And the length of the dynamic cable can be reduced, so that more effective cooling can be achieved. The consortium also plans to develop a 245-kV dry-mate connector, based in extending Baker Hughes’ existing 145-kV connector that has been in use since 2015 on Åsgard subsea compression.”
MECON connectors could also allow longer power-from shore step-outs to offshore oil and gas platforms. Norway has led the way in this development as the government pressures operators to cut emissions from platforms by switching from gas turbines to electricity imported from shore via subsea power cables. But as Asak pointed out, most of the country’s platforms are far from the shore. “A challenge with long step-outs is balancing the electrical losses with the cable size, and handling the reactive power produced in the cable.
“One concept for putting in reactive power compensation is a subsea midpoint reactor between the onshore grid and the offshore host. The benefits of the subsea unit are the same as with the transformer: you have more stable conditions for the structures and equipment, and you need less dynamic cable and improved cooling. Also, the midpoint reactor will be located closer to shore than the platform, meaning the topside solution will be reachable from the shore. As the midpoint reactor is part of the power transmission system, so the required voltage for the dry-mate connector will be 132 kV, more likely 220 kV. This reactor is also a potential solution for long step-out floating wind farms.”
