Need for seafloor production systems drives subsea technology development

Although a growing number of equipment manufacturers and service companies are focusing their research and product development efforts on the subsea, perhaps the best known bellwether is Statoil. In fact, the company considers the subsea factory strategy so important to its future, that it has trademarked the name “Statoil Subsea Factory.”

Statoil’s initial subsea factory unit is scheduled to debut by 2020, Fig. 1. Margareth Øvrum, executive V.P.–Technology, Projects and Drilling for Statoil, has stated publicly that she will not leave until the factory is a reality.

Fig. 1. Statoil subsea factory concept.

“I was instrumental in setting this ambition, and it is a bold target,” she told the Offshore Technology Conference last year, stressing that systematic efforts are being made to ensure that the missing pieces fall into place.

Øvrum also stated that subsea gas compression will be a reality by 2015, when it will be installed in Åsgard field, Fig. 2.

Fig. 2. Statoil subsea compression concept, compared to the size of a typical sports stadium.

Statoil recently entered into a joint industry program (JIP) with ABB, the Zurich-based developer of power and automation technologies. According to ABB, the program will develop solutions for transmission, distribution and power-conversion systems, designed to power and control subsea pumps and gas compressors at depths of 3,000 m over vast distances, Fig 3. The agreement is an important step on the path to developing complete subsea oil and gas producing facilities.

Fig. 3. ABB subsea venturi with manifold, dual-subsea transmitters and umbilicals.

Statoil is leading the JIP on behalf of other participating oil companies, while ABB is responsible for developing the new technology. The JIP follows an extensive subsea power study executed by Statoil and ABB during 2012. The total value of the agreement is $100 million, which will be funded jointly by all participating companies.

According to ABB, the five-year program is pivotal to the development of technologies required to power and control large-scale subsea pumping and gas-compression projects planned for the Norwegian Continental Shelf, the Gulf of Mexico and other locations worldwide. Subsea pumping and gas compression contribute to improved utilization of oil and gas resources through greater recovery rates, reduced production costs and the further development of deepwater production.

The JIP will provide solutions for transmission of electrical power up to 100 MW, over a distance of 600 km and to depths of up to 3,000 m. This is important, notes ABB, for the development of remote oil and gas fields located far from other infrastructure.

The main objective behind the development effort is to provide a cost-efficient, reliable solution, using a single cable to control subsea equipment over long distances, rather than multiple cables for each component. The subsea electric power distribution technology enables several electric loads, such as pumps and compressors, to be supplied through a single power cable, and will reduce investment costs, compared to existing solutions that use one cable for each individual load. Statoil believes that the new technology will bring savings of more than $500 million, if eight loads are linked through a single cable over 200 km from other infrastructure.

To ensure compact and reliable solutions, the equipment will be enclosed in liquid-filled, pressure-compensated tanks, with components tested extensively under the full pressure that they will experience at the target water depth.

Electrical subsea power. With an eye on providing the subsea electrical power, GE Oil & Gas, through research at its GE Global Research Center, has developed a power transmission and distribution concept called modular stacked direct current system (MSDC). The MSDC technology achieves the required DC transmission voltage by stacking a number of power-converter building blocks in series, both onshore and on the subsea field, Figs. 4 and 5.

Fig. 4. GE subsea power converter unit.

Fig. 5. GE subsea MSDC system.

On land, the converter system is controlled, to maintain a constant current in the DC cable, regardless of the loading condition. On the subsea end, each converter module is coupled directly to each individual motor load. Since the current in the DC cable is regulated continuously by the onshore station, the operations of the different subsea modules are decoupled.

Compared to the modern land-based HVDC system, the centralized converter station is no longer needed, and fewer subsea electrical components are required for the MSDC structure, according to GE. The modularity of the MSDC architecture will render the system fault-tolerant and capable of operating in a degraded mode. The architecture is also reconfigurable as the field matures, and the loads evolve over time. Therefore, the technology potentially offers a much lower-cost, higher-reliability, subsea power solution.

In addition to the system architecture, the GE team also developed the cooling and packaging concept for the electrical equipment to be deployed 10,000 ft below sea level. A multiphase cooling approach was selected, that the company says combines reliability, electrical isolation, and thermal performance by using a pool boiling solution in a sealed pressure vessel.

Deepwater subsea systems. Meanwhile, across the world in Indonesia, Italian company Eni is leading in the development of Jangkrik field, in the Muara Bakau Block, offshore Kalimantan, 44 mi (70 km) from Balikpapan in 200–430 m of water. Eni operates the block with 55% interest, while France’s GDF Suez controls the remainder.

In February, Eni awarded an estimated $720-million contract to FMC Technologies to supply subsea systems for Jangkrik. FMC Technologies’ scope of supply includes subsea trees (Fig. 6), manifolds, jumpers and connection systems, umbilicals, tooling, and associated topside and subsea controls systems.

Fig. 6. FMC Technologies’ Enhanced Horizontal Subsea Tree (EHXT) is rated for up to 10,000-ft water depth and pressures up to 15,000 psi.

The hydrocarbon discoveries in Jangkrik and Jangkrik North East fields hold estimated proven reserves of more than 1.3 Tcf. The fields are expected to begin production in early 2017, with a peak production of 450 MMcfgd.

Eni also recently awarded French engineering company Technip a contract to supply engineering, procurement, commissioning and installation of 36 km of flexible risers and flowlines, with diameters ranging from 4 in. to 14 in.; 195 km of pipeline with diameters ranging from 4 in. to 24 in.; and subsea equipment that includes mid-water arch and flowline-end termination.

Technip will also carry out the installation of 51 km of umbilicals, five manifolds and seven SSIVs (subsea isolation valves), subsea structures and associated flying leads. Finally, the project includes the engineering, procurement and construction of an onshore receiving facility that includes pig traps, metering systems and utilities.

The flexible pipes will be manufactured at Technip’s Asiaflex Products plant in Tanjung Langsat, Johor, Malaysia. Technip’s S-Lay and heavy-lift vessel, G1201, and its multipurpose installation and construction vessel, the Deep Orient, will be used for the installation. The project is scheduled to be completed in first-quarter 2017.

Finally, Eni has awarded a consortium, led by Saipem, a $1.1-billion EPCI contract for a newbuild floating production unit (FPU) for Jangkrik. The consortium includes Hyundai Heavy Industries Ltd (HHI) and a joint venture of Saipem, Tripatra Engineers & Constructors, and Chiyoda. The scope of work includes engineering, procurement, fabrication of the FPU, and the installation of a mooring system. as well as hook-up, commissioning and assistance with start-up. The spread-moored FPU will have a treating capacity of 450 MMcfd of gas and condensate.

Major Congo development. Offshore Congo, Total, operator of the Moho-Bilondo license, has made the final investment decision, as well as EPC contract awards for the Moho Nord development, consisting of the Moho-Bilondo Phase 1bis and Moho Nord projects. First oil is expected in 2015, with output reaching 140,000 boed in 2017. The joint development represents an investment of $10 billion.

Located 75 km from Pointe-Noire, in water depths of 1,969 ft to 2,625 ft, the Moho Nord project will target additional reserves in the southern portion of the license (Phase 1bis)and new reserves in the northern part (Moho Nord). The additional reserves are estimated at about 485 MMboe.

The project is the latest step in developing the license, following Moho-Bilondo Phase 1E, which was brought onstream in 2008.

For Phase 1bis, a total of 11 subsea wells in the Miocene will be tied back to the existing FPU on Moho-Bilondo, whose processing capacity will be increased by 40,000 boed. For Moho Nord, 17 subsea wells targeting Miocene reservoirs will be drilled and tied back to a new FPU, and 17 more subsea wells targeting Albian reservoirs will be developed from a newbuild TLP. Before being exported by pipeline to the onshore Djeno terminal, new production will be processed on the FPU, which will have a capacity of 100,000 boed.

Subsea pumping systems. OneSubsea has been awarded a pump systems contract for the Total Moho Phase 1bis development, offshore Congo, in water depths ranging from 1,969 ft to 2,625 ft. The scope of supply includes a multiphase pump station with two off 3.5-MW high-boost pumps; a power and control module; a power and control umbilical; and PhaseWatcher subsea multiphase flowmeters with Vx technology for pump control. Manufacturing and testing will take place at OneSubsea’s Horsøy facility in Norway.

“This is our fourth contract to provide booster pump systems for Total E&P,” said Atle Ingebrigtsen, president of the OneSubsea Processing Systems division. “Our experience in delivering more than 25 of these systems will enable us to support Total in increasing the production and extending the life of the Moho-Bilondo field.”

Meanwhile, Total E&P Congo has awarded Technip an engineering, procurement and supply contract for the Moho Phase 1bis development. The contract covers the project management, detailed engineering, procurement and supply for the modifications of the Alima FPU, with two new subsea tie-backs.

Technip’s operating center in Paris will manage the contract, which is scheduled to be completed in first-quarter 2015. Technip will also provide assistance to Total for the offshore construction phase from 2014 to 2016.

Total last year awarded Aker Solutions an $850-million contract for the delivery of a subsea production system for Moho Nord.

Scope of work within the contract includes delivery of 28 vertical subsea trees, including wellhead systems, two installation and workover control systems, seven manifold structures, and subsea control and tie-in systems. The contract contains options related to Moho Nord that Total may exercise.

The project will employ Aker Solutions’ vertical tree technology. The first deliveries of the Moho subsea production system will be made in second-quarter 2014.

Total E&P Congo operates the Moho-Bilondo license with a 53.5% interest, with state-owned Société Nationale des Pétroles du Congo (15%) and Chevron Overseas Congo (31.5%).