Lower oil prices have increased the pressures on North Sea platform operators striving to delay decommissioning. This is an issue facing not just older installations that have exceeded their design lives but also some of the newer facilities.
Neptune Energy’s Gjøa and Spirit Energy’s York platforms were designed for long-term service on reservoirs with uncertain lifespans. Both fields have now entered the tail-end phase: Gjøa’s partners have responded by instigating three simultaneous tiebacks, two of other fields in the area, to ensure continued take-up of the platform’s processing capacity. Spirit is currently re-routing York’s gas to another terminal providing compression in order to extend the field’s lifespan by up to four years.
Norsk Hydro discovered Gjøa in 1989 in the northern Norwegian North Sea, 50 km (31 mi) northeast of the Troll field, with StatoilHydro (later Statoil) securing approval for the development from Norway’s parliament in mid-2007. On its own, Gjøa was considered marginal based on understanding at the time of the oil and gas resources and the segmented reservoir, but the project became viable through factoring in subsea tiebacks of Statoil’s Vega field, 28 km (17.4 mi) to the west. Under a prior arrangement, partner GDF (subsequently renamed ENGIE E&P) became operator once production had started. Neptune Energy in turn took control in February 2018, following its acquisition of ENGIE.
Gjøa’s semisubmersible production platform, moored in 370 m (1,214 ft) of water, 120 km (75 mi) northwest of Bergen, began operating in November 2010, and was engineered to serve from the outset as a hub for fields in the area. Samsung Heavy Industries constructed the hull in South Korea, with Aker Kvaerner in Stord, western Norway, responsible for the topsides and integration with the hull. FMC Technologies supplied the subsea production systems, connected to 4x4-slot seabed templates at drill centers on different parts of the field, and one-single slot template on the P1 segment in the northern part. Vega, operated by Wintershall Dea since 2015, is linked to Gjøa via three four-slot templates: one each on the Vega North and Central gas-condensate accumulations, and one on Vega South, where gas-condensate is overlain by an oil zone.
Much of the power needs of the platform and the subsea facilities is hydropower-generated electricity transmitted via a 98-km (61-mi) submarine cable from Mongstad on Norway’s west coast. ABB supplied and installed the 90 kV, 40 MW AC subsea power link which was the first of its kind at any field on the Norwegian shelf. Remaining power on the platform comes from a Siemens/Dresser Rand compression package comprising a GE LM2500 gas turbine.
To date both Gjøa and Vega have produced through pressure depletion. At Gjøa, the initial focus was on the oil from thin zones in the southern segments. Production of the gas cap, via blow-down, started in 2015 with low-pressure production instated two years later. Stabilized oil from Gjøa and Vega is exported through a connection to the Troll Oil Pipeline II to the Mongstad terminal. Liquids-rich gas is sent for processing to the St Fergus terminal in Scotland via the North Sea FLAGS pipeline.
Neptune estimates remaining reserves across the Gjøa license (PL 153) at 106 MMboe, with a 60% gas fraction. The platform can process 17 MMcm/d of gas in the present low-pressure mode, and 87,000-90,000 b/d of liquids: studies are also under way to determine whether liquids exports could be boosted through adding pumping capacity. “We are preparing for what might be around the corner,” said Martin Borthne, Neptune’s Head of Operations in Norway, with tiebacks of other fields in the area under discussion aside from the three current projects. Wintershall Dea is also thought to be considering drilling three more wells via the Vega templates.
Under Neptune’s stewardship, Gjøa’s existing management team and platform personnel have largely been retained. “During the process of reassignment of operatorship, we set up ring-fenced procedures to ensure that we didn’t negatively impact the performance of the offshore teams,” Borthne explained. “When we took over in early 2018, we found that the facility was in excellent condition. It was designed effectively as a sister platform to the Kristin field semisubmersible in the Norwegian Sea: the strategy StatoilHydro was following in the 2000s was to incorporate a lot of high-grade, corrosion-resistant steel into the construction, with the result that today, the Gjøa platform looks newer than 10 years old, with no corrosion and in the upper range of topsides equipment availability.
“Up to now, Gjøa has followed its initial drainage strategy with only minor adjustments, including the delayed gas-cap blowdown and subsequent low-pressure production. The production performance for oil has been better than prognosed, mainly due to weaker aquifer drive and active production optimization.”
However, action had to be taken to counter a steep production decline by adding volumes from outside the Gjøa area. Wintershall Dea, a partner in the PL153 license, had an agreement in place for a tieback of its 80-MMboe light oil and gas Nova (ex-Skarfjell) discovery in PL 418, 17 km (10.6 mi) to the southwest. The plan for development and operation (PDO) was approved by the Norwegian authorities in October 2018. Shortly afterwards, Neptune submitted its own proposals for Duva (formerly Cara), discovered by the PL636 licensees in 2016, 6 km (3.7 mi) northeast of the Gjøa field and thought to hold 88 MMboe recoverable, mostly gas.
The third piece in the puzzle was a redevelopment of Gjøa’s P1 segment, discovered in 1989 in 340 m (1,115 ft) water depth. Drilling proved gas in the Viking, Dunlin and Brent formations with evidence of oil too in the Dunlin section in the lower part of P1, potentially a 100-MMboe resource. There was no commercial solution for producing the oil during the original Gjøa development, but an option was left open in the PDO to do so in the future. Neptune and its partners decided to capitalize on that exemption by executing development in parallel with Duva, launched in February 2019. P1 is now thought to hold 32 MMboe recoverable.
TechnipFMC is supplying the subsea production and SURF systems for both projects, under a frame agreement with Neptune. The subsea trees, connected to four-slot templates, will be the same configuration that FMC provided for the original Gjøa development. P1’s two wells will be connected via a single template to the platform. Duva’s template, connecting one gas and three oil producers, will be operated from the platform via a dedicated umbilical. Duva’s wellstream has a high wax content: the wax appearance temperature of a Duva sample revealed a need for a pipe-in-pipe solution for flow assurance, to avoid the risk of waxing down the flowline in the event of low-rate production. In addition, a dedicated wax inhibitor injection skid is being installed on the platform.
Nova’s two templates – one with three oil producers and another with three water injectors – will be linked via four flowlines to the platform where the oil and gas will undergo processing and export. Heerema’s crane vessel Sleipnir installed an associated new 718-t module on the platform in May, housing the 9-in. water injection riser, 5.5-in. gas-lift riser, 8-in. and 12-in. production risers. The module, constructed by Rosenberg Worley in Stavanger, will supply lift gas and water injection exclusively to Nova. Borthne explained: “This is not because Wintershall Dea is the operator, but Nova needs water injection. We have not had that on Gjøa because up to now there has been no need for pressure support. Also, what Nova needs in terms of gas lift is beyond what can be handled by the platform’s gas-lift compressors. Due to the amount of additional equipment required, it was more sensible to package these systems into one module for Nova: the platform’s original design had set aside a large gap in the middle for future add-ons, and it was simply a case of lifting the module onto that space.”
Synergies were achieved by having Rosenberg Worley construct topsides equipment for all three projects. As for the subsea tie-ins, “when the decision was taken on Nova, P1 and Duva were still under review, and Wintershall Dea, as operator, chose the subsea contractors which are not the same as for the other projects.” Aker Solutions is supplying Nova’s subsea productions systems, with Subsea 7 constructing and installing the SURF systems. In addition, Seadrill’s semisub West Mira will drill Nova’s wells while the semisub Deepsea Yantai, operated by Odfjell, is engaged for the PI and Duva wells.
Although Neptune has not so far introduced major changes to equipment on the platform or to Gjøa’s operating methodology, the company is assessing various efficiency measures. One development with DNV Marine is a vessel monitoring system that would use AIS data and weather forecasts to manage offshore vessel movements in the area. “With the three concurrent projects there is a lot of activity involving rigs, pipelay, subsea construction and support vessels,” Borthne said. “We need to optimize the way we bring vessels into the safety zone. We ran a trial of the new system during the previous platform shutdown.
“We are now introducing a pilot solution for ‘Connected Worker’ digital Ex equipment and applications to ensure a stronger integration between the offshore and onshore organizations. The intention is to provide a better interface and availability to the volume of data and information generated, as well as streamlining the collection of information from the offshore field individual. Despite having been 10 years in operation, Gjøa is a very heavily instrumented and digitalized facility.
“We have also launched a technical collaboration with Stinger Technology in Stavanger concerning a permanently installed underwater vehicle for inspection, capable of operating in 400 m [1,312 ft] water depth. This could be deployed every time we need to perform inspections of risers, flowlines and other subsea structures in the Gjøa area rather than having to bring in a vessel with ROV capabilities. An autonomous underwater vehicle will have a significantly shorter response time, provide much higher inspection frequency, and avoid the weather dependence associated with conventional launching of ROVs through the splash zone.”
Gjøa’s subsea AC power cable, installed in 2008, remains in good condition with no immediate need to upgrade the power system. “We plan to take an extra 50 MW of power cable in total with the three new projects: studies indicate that potentially we could even go beyond that. Norway’s onshore grid currently seems to be the main bottleneck, with so many new North Sea oil and gas projects wanting to take power from the same area, so significant work has started on reinforcing the transmission system.”
The ongoing projects on Gjøa are all managed through one common organization within Neptune. Three simultaneous tiebacks are a complex undertaking and may be unique in the history of the Norwegian shelf, Borthne suggested. “Having said that, making sure we wouldn’t step on each other’s toes turned out to be more of an issue than securing approvals for the developments with the Norwegian authorities. But overall the experience has been good so far, and all the projects have benefited from the synergies this execution model has generated.
“Operations have been somewhat affected by COVID-19. There are 100 single-person cabins on the platform’s living quarters, and capacity has had to be restricted to 85, with one wing kept free in case an outbreak of coronavirus arises. Measures are also in place to evacuate affected people safely to the shore, and for the latest work we have bought equipment to test personnel heading to the facility. Now that the situation has eased somewhat, we are going back to a full personnel onboard complement of 100 persons, but that can be reduced if things change quickly.”
P1 is on course to start-up later this year, two months ahead of schedule with Duva and Nova to follow during 2021. Another candidate for a future tieback is Wellesley Petroleum/Neptune’s Grosbeak discovery in PL 925, 18 km (11.2 mi) southwest of the platform: according to Borthne, the Gjøa partners have already made their pitch. There will probably be spare capacity for third-party fields on the platform once the current projects come off plateau around 2023-25, he added.
York production switch
Spirit Energy plans a series of measures to prolong production from the York gas field in the UK southern North Sea until potentially 2024. The York Life Extension project, to be phased across 2020-21, will include modifications to the platform and control systems; re-routing production to the Perenco Dimlington terminal on the East Yorkshire coast; and a workover of the Y1 well.
York comprises various reservoirs across four blocks in an average water depth of around 45 m (137 ft). Centrica started production early in 2013 via a normally unmanned platform, 34 km (21 mi) from the northeast Yorkshire coast: the gas was exported through a 16-in., 120-MMcf/d capacity pipeline to the Easington terminal, with a 3-in. piggybacked line taking methanol in the other direction. The Heerema Hartlepool yard in northeast England built the platform, which comprises a four-legged, cross-braced jacket accommodating six well slots, plus risers and J-tubes. The three-level topsides includes overnight accommodation for maintenance staff for use in bad weather. Jacket, deck, and piles have a combined weight of 3,700 metric tons (4,079 tons).
At the time of development this was one of the largest fallow gas accumulations in the UK’s southern sector, but also one of the more technically challenging to produce. One of the issues was the field’s shared fault with the Rough reservoir 3 km (1.8 mi) to the south, which at the time served as the UK’s sole offshore storage site. Recently, however, Centrica discontinued gas storage operations at Rough due to safety concerns following a site review.
Since start-up, York has produced 45 bcf via three wells, and Spirit – co-owned by Centrica – plans to develop a further 18 bcf over the field’s remaining life. According to Girish Kabra, Director of the company’s North Sea Operated Assets, the review of the York reservoir and its life extension started in 2019 and is part of a systematic investigation of all the company’s operated facilities and reservoirs in the region, some extending into Dutch waters.
According to Kabra, York’s recoverable volumes were historically restricted by an agreement with Centrica concerning communication with Rough, which was amended in recent years to be less restrictive, and also by the high degree of compartmentalization within the York field itself. “The latter means that each current producer is draining certain compartments whereas others don’t have any producers at all. We are currently able to operate at reduced pressure in York which has its own benefits and our decision to re-route production to Dimlington should increase the final expected recovery - at the same time, providing a positive operating environment for additional wells and the Y1 well intervention.
“Currently York is ‘in hibernation’, as modifications are under way at the Easington terminal to receive gas from Premier Oil/Dana Petroleum’s Tolmount field. When York resumes operations in 2Q 2021, all three wells will be in production. Due to the geology, most of the southern North Sea gas fields are susceptible to halite (salt) formation which is dissolvable by fresh water. The purpose of the Y1 intervention is to unblock the halite and unload the water from that well.”
At the same time, Spirit is re-assessing infill opportunities on the field under the new operating conditions in order to increase recovery, Kabra said. “The platform originally had a design life of 25 years and was built as a hub for third-party tiebacks, with spare j-tubes and spare risers. We are constantly evaluating the new opportunities.”
Under the original development, York had access to a slugcatcher at Centrica’s Easington site which formerly processed fluids from the Amethyst platform. Perenco has since shut down the Amethyst field; however, Amethyst infrastructure at the Dimlington terminal will be re-used for York. In fact, Centrica had originally explored tying York’s production through the Cleeton-Dimlington subsea pipeline, but BP, the pipeline operator at the time, vetoed that option. With the new arrangement, the Dimlington terminal will provide remote control and operation of York’s platform. “Spirit also produces other subsea fields such as Seven Seas, Eris and Ceres from Dimlington,” Kabra added, “so taking York to Dimlington to access its low-pressure compression was a good proposal.
“York’s production will continue to head through the existing 34-km (21-mi) pipeline to Easington, with modifications performed there to re-route the pipeline to the existing Amethyst pipeline to Perenco’s Dimlington terminal. At the same time, the infrastructure and control room formerly dedicated to York at Easington will now serve Tolmount.”
At the Chiswick field platform, 121 km (75 mi) from the Norfolk coast, the company has added two new production wells over the past 18 months as part of a life extension program designed to access a further 50 bcf of reserves. The field, originally developed by Venture Production, came onstream in 2007. “In March 2020,” Kabra said, “we drilled and completed the C6 well, which has performed better than prognosed. C5, which came online in July 2019, provided some useful reservoir and product information that our subsurface team is currently looking into to see whether there are a further one or two targets in the field. Chiswick remains one of the highest production fields in our operated asset base.
“In the same region, we are evaluating an option to appraise a Grove NE structure with our partner Viaro Energy (formerly RockRose Energy). If we do drill the well and it comes in as per the subsurface prognosis, we expect to extend the life of the Grove platform and facilities until 2027-29. If it doesn’t, we would expect production from Grove to cease in 2022.”
Chiswick and Grove both export their gas to the J6A platform in the Markham area on the Dutch side of the North Sea median line. The Markham J6A platform was built and installed in 1992 and according to Kabra, has been well maintained by the crew, with Spirit committed to further investment and upkeep of the facilities. “The Markham partners were looking to conduct a major barge-based campaign this year to make the platform fit for service for the next decade, including upgrades to the accommodation and power generation system. Due to COVID-19 restrictions that work has had to be deferred to 2021; once completed, the J6a facilities will be good for the next eight to 10 years to support Grove, Chiswick, and other connected third-party fields.”
