Investment plans on the UKCS

December 28, 2017

UK operators have gone a long way to reducing their costs and are even starting to look at investment, delegates attending the Oil & Gas UK Share Fair in Aberdeen early November learned. Elaine Maslin reports (First published in the December 2017 OE, access the full issue here).

Most in the oil industry are keen to start hearing some good news, ideally in the form of new contracts and investment. 

Apache's Beryl field infrastructure. Image from Apache.

While it may not have been an announcement about a major new project, a comment by Apache’s supply chain manager Stephen Duncalf, was enough to keep those at the Share Fair alert. 

“In the Beryl area, there are so many potential barrels that it could potentially be one of the last producing assets in the North Sea,” Duncalf told the event. Given that the Beryl facilities are one of the older facilities in the UK North Sea (Beryl came on stream in 1976 and was bought by Apache from ExxonMobil in 2011) and that new projects are still coming online and indeed are yet to be developed, it’s a bold statement. 

Behind the comment, and others’ comments at the Share Fair, is a focus on low operating costs. Apache, since its entry to the North Sea in 2003, acquiring the Forties field assets (also from the 1970s) from BP, has kept its costs low. Faced with the low oil prices, having got used to a $100/bbl world, many others are following suit. 

Apache’s operating costs put it seventh out of 26 in Oil and Gas Authority rankings (pitting it against far newer facilities with higher daily production levels). Nexen, which also presented at the event and is a company with newer facilities such as Buzzard and Golden Eagle, lays claim to the lowest lifting costs in the basin, at $6/boe – down from $10/boe last year. 

Not all have been performing so well, but some have still improved in recent years. Repsol Sinopec Resources UK, again, also presenting at the Share Fair, meanwhile says it has reduced its lifting costs from $116/boe to $37/boe, showing the amount of work some operators have had to do to become near profitable. 

Production efficiency (PE) is also a key metric of how well firms are operating. Apache’s, by hub, is 95.2%, compared to a basin-wide average at 73% (up from just 60% a couple of years ago), putting close to the top of the performance rankings. Repsol has managed to increase its PE from 33% to 66% in the past couple of years (HSE performance has also improved – something likely linked), a Repsol presenter told the event. A lot of this has been about increasing production – the firm saw its lowest production levels in 2014, in what looked like a terminal decline curve. But, in 2017, it expects to achieve the same production levels as it had in 2012 – while having also ceased production on its Saltire, Beatrice and Buchan assets in the intervening period. Part of Repsol’s focus has been working with more contractors – it has increased the number of tier one contractors it works with from eight to 27. 

Having low operating costs and high production efficiency is not just about enabling profitability, however. A key driver for many of these firms is pushing forward decommissioning. It’s also about making the business competitive compared to other parts of their respective global businesses – if they’re not competitive, the group will not invest. “We’re returns focused, not production focused,” Duncalf says. It’s about holding production flat, maintaining opex/bbl, extending asset life and delaying decommissioning, he says. A representative from Nexen also said: “The key challenge is pushing out the cessation of production date as far as possible and globally we need to compete with capital.”

Apache, Nexen and Repsol, alongside EnQuest, presented some of their investment plans at the Share Fair. OE takes a look at each below. 


Nexen is in the define stage of its Buzzard Phase II project. The proposal is an 11-slot combined production and water injection manifold at a new drill center tied back about 5km to the Buzzard facilities. 

Detailed design for the subsea infrastructure and topsides modifications is running from Q4 2017 to Q1 2018, led by Aker Solutions. Contracts to be agreed include a semisubmersible for drilling and the subsea EPIC contract. 

Nexen's Golden Eagle field. Image from Nexen.

Nexen is also working on a water injection project. Water injection facilities were installed 1993 on the Scott development. Water injection is by three water injection clusters east, south and west of the Scott platform. Nexen wants to replace about 10km of pipelines and umbilicals in the system. It’s at the select phase. Design considerations on the project include how much umbilical and pipeline to replace. A decision is due to be taken, and Nexen expects to go to the market in Q1-2 2018, with an installation date still under review. 

Meanwhile, the firm is drilling the ST37 infill well on Scott and it has a future infield drilling program there. It also has a Telford infill program, eyeing three prospects (Dunkeld, Rossini, and Comet) and one lead, Daffodil, and considering tiebacks, with two discoveries already made, Ravel and Bugle South, which will go through a stage gate process.

It will have semisubmersible drilling rig requirements for infill drilling on Golden Eagle. It was nearing an award for a semisubmersible for plugging and abandonment drilling on Ettrick and Blackbird, and an invitation to tender has been issued for Buzzard Phase II drilling. 

Nexen will use the CJ18 jackup on Blackbird to drill a well on the Glengorm high pressure, high temperature (HPHT) prospect in 2018. Maersk Drilling was awarded a contract for three wells, plus options, for drilling over the Buzzard platform, starting July 2018.

Nexen is currently drilling a well at Craster, west of Shetland. The firm also is planning an exploration well in license LO 16-7 in the Porcupine Basin about 215km offshore Ireland, in about 2000m water depth, in summer 2019, with a drillship, following its success in the 2015 Irish Atlantic Margin Licensing Round. Drilling is expected to take 90-120 days. with four license options.

Project challenges over the last year include intelligent pigging, tool reliability challenges such as being stuck, and related operational risks. These challenges also include obsolescence and sustainability related to subsea systems, controls and pipelines for existing assets and infrastructure life extension. 


Apache is targeting one subsea tieback per year, Duncalf says. Its latest tieback, the Callater tieback to the Beryl Alpha platform came on stream in May 2017, following the FNT tieback (OE: February 2017) to the Beryl Bravo platform in 2016. Corona is likely to be next, via two subsea wells with hydraulic submersible pumps, with Storr following that. “Any future investments will be infrastructure-led,” says Duncalf says. 

Since Corona is a heavy oil field this presents a potential challenge relating to comingling fluids, says Duncalf, due to the Beryl Alpha facilities, to which it will be tied, being designed to produce light crude. Challenges will include ways to stop the crude separating out in the concrete storage cells beneath Beryl Alpha. Apache is in the process of submitting a field development plan for Corona and expects first production at the end of 2019.

The firm is operating two platform rigs and one semisubmersible and says there’s potential to add more. 4D seismic acquisition has helped the firm develop targets, although the firm must assess these carefully as it’s slot-constrained on its assets, Duncalf says. “Long-term, the focus is on having drillable targets and focusing on one constant platform drilling string, so we have to be prudent with reservoir management,” he says. Water injection and slot reuse will be part of that. 

The firm will be looking for normally pressure or HPHT pipe in pipe solutions, or bundles, gas lift, ESPs (electric submersible pumps), HSPs (hydraulic submersible pumps), etc., as well as alternative contracting and commercial models. It’s also looking for solutions to help either extend the life of the single point moorings (SPM) in the Beryl field or replace one of them. Crude is stored in the Beryl platform’s concrete cells and offloaded to tankers via SPM 2, with SPM 3 acting as a backup. 

“Maintaining them is a challenge we have had for several years now,” Duncalf says. “There’s a challenge of accessibility, and being able to maintain and inspect them appropriately throughout the year. We’re looking for smarter solutions for maintenance and inspection, also possible alternatives so we could perhaps remove at least one of them.” 


North Sea independent EnQuest has been growing. The firm, which estimates 37,000 boe/d production for 2017, increasing to 50,000 boe/d by 1H 2018, brought the Alma/Galia development on stream earlier this year, followed by the Kraken heavy oil field, a floating production project, which will continue ramping up into 2018. It also purchased the Magnus asset off BP, giving it 215 MMboe 2P reserves plus 150 MMboe contingent resources to work on.

The Kraken FPSO. Image from EnQuest.

To date, 38mi of hole has been drilled on Kraken, a spokeswoman for EnQuest said. The field is now home to the world’s longest OptiPac (alternate path) gravel pack, at 4347ft, completed in June 2017. The drilling program is 288 days ahead of April 2014 pre-drill estimates, EnQuest says. Some of this has been due to batch drilling, using video footage of operations to train staff before they go offshore, and cost reduction through supply chain management and drilling performance. All top holes have been drilled with riserless mud recovery, enabling 45-degree angles in the tophole section, cutting 45ft off the length of each well, reducing casing string requirements.

Once EnQuest gets its hands on Magnus, the firm is planning to drill three wells. Other projects the firm is working on include optimizing the Scolty Crathes tiebacks with a new pipeline and chemical treatments in 2019. EnQuest is targeting its Eagle development planning, looking at subsea electrical subsea pump workovers on Alma/Galia, continuing scale squeeze work on Kittiwake and the Dons, and performing plugging and abandonment work on Thistle and Heather, which will help open space for a new Heather development well. EnQuest is planning ESP workovers on Thistle, possibly using coiled tubing. The Dunlin bypass is due to be awarded (with a view to 2019 execution), as well as the Thistle gas compressor project.