Stephen Whitfield takes a look at some of the major development projects now utilizing subsea separation and processing technology to increase field life.
Several companies are looking at subsea processing and separation as they try to maximize production out of difficult projects. Recently, developments have sprouted in new and aging fields the world over, from the Gulf of Mexico to the Norwegian coast to West Africa. Here is a look at some of those developments from three top companies.
Within the next 12 months, Norwaybased Aker Solutions expects to have the world’s first subsea gas compression system up and running in the Åsgard field of the coast of its home country (OE: August 2013).
The Åsgard field is located on the Haltenbank in the Norwegian Sea, about 125mi off the Norwegian coast and 31mi south of Statoil’s Heidrun field. Petoro owns a majority stake in the field, with a 35.69% share, but Statoil is the operator of the field. Statoil has a 34.57% share, Eni Norge has a 14.82% share, Total E&P Norge owns 7.68%, and ExxonMobil owns 7.24%.
According to Statoil, by the end of this year pressure in both of Åsgard’s subsea satellites (Midgard and Mikkel) “will become too low to sustain their ability to produce to the B platform,” leaving the company in a lurch. Until recently, the typical solution for a problem like this was to install gas compressors on an existing surface platform, or build an entirely new manned compression platform.
Statoil has chosen a different approach: installing the compressors on the seabed, near the wellheads. It’s cheaper and it doesn’t require as much additional manpower as a new platform. The only problem was that it hadn’t been done before.
That is where Aker Solutions came into the picture. In 2010, the company was awarded a contract to develop a subsea compression system for the Åsgard field, with a target date of 2015 to have everything up and running. So far, thing appear to be running on schedule: Aker Solutions finished the steel frame for the facility in June 2013, and it was installed on the seabed within two weeks of its delivery.
So how will it work? The contract Aker Solutions received to develop the compression system for Åsgard called for a gas cooler and a liquid separator in addition to the compressor. According to Statoil, the electricity used to power the compressor will come from the Åsgard A oil production ship. A motor in the compressor that consists of a number of vanes around a shaft will convert this energy to mechanical energy. Gas will enter the system at a low pressure and, after a gradual compression process, will exit at a higher pressure sufficient enough to move through the pipeline to the receiving platform.
Construction on the Åsgard unit should be completed soon. The three compressor trains are scheduled to be delivered this year, and startup of the full station is scheduled for 2015. Statoil expects to recover 280MMboe after the system’s installation.
Åsgard is not the only subsea compression system in the works for Aker Solutions – the company also has one planned for Ormen Lange field, and the second-largest gas field off the Norwegian coast. Like Åsgard, the Ormen Lange unit is designed to run entirely on electric power: a subsea power cable connected to a transformer would transmit about 58MW of power to the compressor, with the power being contributed through a circuit breaker module. The circuit breaker would be surrounded by an enclosure filled with nitrogen at atmospheric pressure.
Ormen Lange is operated by Norske Shell, and the compression system is designed to run at 2950ft. According to Aker Solutions, it should be operational by 2020.
For much of the past decade, FMC Technologies has been heavily involved in the boosting systems at Shell’s BC-10, a complex off the Brazilian coast. When the system came online, it was the first full-field development comprised around subsea oil and gas separation.
The project, also known as Parque das Conchas, consists of three small and mid-sized fields – Abalone, Ostra, and Argonauta – that range in depth from 4900-6560ft. Its heavy oil reserves and low reservoir pressures presented a significant challenge in terms of maximizing the field’s production.
BC-10 utilizes caisson boosting systems, as opposed to installing electrical submersible pumping systems at each wellhead. Each caisson was installed vertically into the seafloor, at an approximate depth of 330ft. Separation comes from the gas-liquid cylindrical cyclonic process, as the raw wellstream swirls thanks to a tangential inlet to the top of each caisson. Gas comes into a riser through the caisson’s center, while oil goes down the side of the caisson.
For the first phase of construction, FMC Technologies provided ten of its then recently-created Enhanced Vertical Deepwater Tree systems, each of which had a bore size of 5.2in. and a 10,000psi rating.
BC-10 has been developed in phases.Phase I came online in July 2009. It focused on the lighter oil reserves found in Abalone and Ostra. Separation was only used in reserves with a gas-to-oil ratio above 40%, but all of the targeted reserves were boosted to relieve approximately 2,000psi of back pressure.
The second phase, which was completed last year, involved the delivery of 11 subsea trees and four subsea gasliquid separation units, along with their related controls. In September 2013, FMC Technologies announced its contract for the third phase of development, which includes seven more subsea trees, two manifolds, tie-in connection systems, and subsea distribution hardware.
BC-10 was just one of several projects in which FMC Technologies delivered some significant advancement in subsea separation technology. The Total Pazflor project, located in Block 17 off the coast of Angola, marked the first use of subsea separation technology in West Africa. But its influence may be in its sheer size: its three separation units (SSUs) weigh nearly 1200-tons, operated at 333psi, and can process 110,000b/d. With the SSUs in place, a gas-tolerant pump can push oil and water to the surface.
Pazflor drew first oil on 24 August 2011. Two years later, in March 2013, FMC Technologies delivered a subsea separation system to Marlim, a large mature field operated by Petrobras in the Campos Basin offshore of Brazil. It is the first such system to boost production of a mature field that also includes the reinjection of previously-removed water.
OneSubsea has several projects currently underway in the area of full wellstream subsea boosting that are expected to begin production either later this year or early next year.
Notable among these projects is Draugen Field, located in block 6407/9 in the Haltenbanken area, approximately 87mi north of Kristiansund, Norway (OE June 2013). The field was discovered in 1984 and production began in 1993. It currently consists of 13 production wells – seven of them subsea.
The Garn West Reservoir ties back to the Draugen platform through a 2.05mi pipeline. Gas exports are transported through the Åsgard Transport pipeline to Kårstø. Norske Shell is the operator of the field, owning a 26.20% stake. Petoro owns a plurality stake at 47.88%, with BP Norge and Chevron making up the rest.
As with any aging field, production at Draugen had dropped off precipitously heading into its second decade of operation. In 2009, the field’s average crude oil production was 63,000boe/d, 14% less than the previous year and 56.25% less than its average production from five years earlier.
OneSubsea will develop four new production wells in the field. These wells are located at a depth of 879ft, and all of them will be routed to a new pump located between the platform and the reservoir. This pump, which OneSubsea will also deliver as part of its contract, is a helicon-axial pump with two units.
The subsea boosting pump at Draugen is scheduled for a June installation, and the new wells are expected to be operational in the third quarter of this year. Also scheduled to wrap up this year is Jack/St. Malo, a new project that combines two fields located in the lower tertiary trend of the Gulf of Mexico. The Jack field is in Walker Ridge blocks 758 and 759. Chevron holds a 50% interest in the field, which has a water depth of 7201ft. Maersk has a 25% stake in Jack, as does Statoil.
St. Malo is not nearly as deep – only 2,100ft. It is also operated by Chevron, which owns 51%. Petrobras (25%), Statoil (21.50%), ExxonMobil (1.25%), and ENI (1.25%) are the other partners. Both fields are located about 300mi off the coast and are expected to last bewtween 30-40 years.
Unlike Draugen, the Jack/St. Malo project is not a case of revitalizing an older field but maximizing potential production in an untapped field. OneSubsea is contracted to build a 12-well system, along with a centrifugal pump and related control systems. It plans to boost production on the seabed as a way increase recovery rates on a field that has yet to draw first oil.
The pump is a single-phase pump operating on 3MW shaft power, with a 13,000 psi pressure rating and a 4000psi boost, which makes it capable of processing up to 60,000b/d.
This is not OneSubsea’s first foray into Jack/St. Malo. In 2009, the company delivered to the project a subsea tree system that incorporated multiphase flow meters and sampling of its Multiple Application Reinjection System (MARS), its first such system to do so. MARS is a universal interface that, according to a company manual, enables “the connection of production optimization systems to be installed easily in the field, either on or off the subsea tree.”