Rig demand and dayrates remain challenging, but exploration appears to be slowly picking up as operators push breakeven levels lower and smaller E&Ps acquire assets from supermajors
By Linda Hsieh, Managing Editor, and Eva Vigh, Editorial Coordinator
Although the North Sea drilling market is still quite a ways from what one might call healthy, small signs of recovery are starting to sprout. Several operators, for example, have publicly touted significant reductions in their breakeven costs for offshore projects – from Maersk Oil’s $40-45 range for pre-FID projects to Statoil’s $27 for pre-FID Norwegian Shelf projects. “It’s absolutely a key factor in returning rigs to work,” said Steven Brady, Senior Vice President of the Eastern Hemisphere for Ensco. “Operators are taking advantage of this cycle to lower their breakeven threshold for offshore developments, and that is allowing them to look at some projects that didn’t appear economical 18 or 24 months ago.”
In particular, the North Sea exploration market is finally starting to pick up again, said David Moseley, Reports Manager for Northwest Europe at Westwood Global Energy Group. “Lower-end rig rates are seeing no sign of increasing, having seemingly hit a price floor, thereby making exploration investment more attractive,” he said, adding that approximately 16 exploration wells are expected to be spudded this year – 10 in the Central North Sea and two each in the Northern North Sea, Southern Gas Basin and West of Shetlands. That compares with 12 exploration wells that were spudded in all of 2016, Mr Moseley said.
He further pointed to the UK’s 29th offshore licensing round, whose results were announced in March, as an encouraging sign. The round, which offered 25 licenses to 17 companies, was the first in two decades to focus on the frontier, underexplored regions of the UK Continental Shelf (UKCS). In fact, by 2020, the West of Shetlands is expected to account for at least 20% of the UK’s overall production, supported by projects such as BP’s Quad 204 and Clair Ridge and Total’s Laggan-Tormore.
Another encouraging indicator this year has been the continued investment into the North Sea of smaller oil and gas companies, mostly in the form of asset acquisitions from supermajors. In January, BP sold 25% of its stake in one of the region’s oldest fields, Magnus, to UK independent EnQuest. Later that month, Chrysaor, another independent, announced that it was acquiring $3.8 billion in North Sea assets from Shell. The assets include Shell’s interests in Buzzard, Beryl, Bressay, Elgin-Franklin, J-Block, the Greater Armada cluster, Everest, Lomond and Erskine, as well as a 10% stake in Schiehallion. “There has been a great investment move into the North Sea by private equities, as the supermajors have tended to shy away,” said Karl Tolson, Wells & Subsea Director for Chrysaor. The acquired assets are expected to add 350 million BOE to the company’s existing reserves base.
“We want to start drilling as soon as we complete this deal,” Mr Tolson said, noting that the company will likely begin with sidetrack wells in the Armada area. “Within two or three weeks of completion of the deal, we want to be mobilizing a rig to the area.” There will be six or seven wells to drill initially, likely a mix of exploration and development wells. “We do see a lot of value in several of the hubs, both in terms of infield drilling and in some exploration potential. We plan a proactive program.”
Looking ahead to anticipated drilling operations on the newly acquired assets, Mr Tolson noted that Chrysaor will be seeking “to do things a little bit differently than the standard North Sea operating approach.”
“We’ve all suffered, but the brunt of the fall in oil prices so far has been taken by the supply side of the industry,” he explained, adding that unprofitably deep discounting is not a sustainable model as it will strip away the supplier base. “The low oil price environment is likely to continue for some time, so we need to get to a place that works for all parties.”
More and better incentives are needed, he urged, where both parties share in both the benefits and the risks. With rigs, for example, that is the only way that two diametrically opposed forces – one wanting to maximize the number of days a rig is working and one wanting to minimize it – can achieve alignment. “I want to get the rig provider and other service partners involved earlier in the process,” Mr Tolson said. This way, operators and service partners can work to optimize the program and set incentive targets, rather than the operator working in isolation and setting targets unilaterally.
“Operationally, this is something we did very successfully in the 1990s, and drilling performance improved and overall well costs dropped noticeably,” he recalled. “We’ve done it before, and I think we need to do it again… and go beyond the old models. In the next 12 months, as the assets are transferred from Shell and as we move forward, we’ll be looking at whether there are any new models that we can apply to the relationships with our service partners that’s going to benefit both sides.”
Continued investment in rigs is a must
While low commodity prices still make the North Sea a challenging market at present, Ensco says it has been able to enjoy higher-than-average utilization rates for its 11 jackups in the region. “Thanks to lots of hard work by our marketing and operations teams, the North Sea has been one of our better-performing markets,” Mr Brady said, citing well intervention and abandonment requirements that are helping to create new work opportunities for rigs in the region. “We have two rigs that have been occupied on long-term abandonment programs,” he said, adding that intervention activities have also increased due to operators’ desire to add low-cost production.
In fact, save for one stacked jackup, all of Ensco’s 10 other jackups in the North Sea are expected to work at some point this year, Mr Brady said. The company recently won a three-well contract with INEOS for the ENSCO 121 that is set to commence in July. ENSCO 92 also recently saw its contract with ConocoPhillips extended by more than four years, which is expected to keep the rig working to December 2022. “The North Sea remains a very competitive market, but we have seen increased utilization across our fleet over the last several months while industry utilization remained essentially flat,” Mr Brady said.
A key to success, he explained, is continued investment in the company’s rig fleet through patented technology. “Ensco has filed 25 patents since 2015, which is more than we had filed in our entire history,” Mr Brady noted. One of these patented innovations is the Canti-Leverage Advantage technology, which has been installed on Ensco’s 120 and 140 Series jackups. The technology enhances hoisting capacity at the farthest reaches of the cantilever when the rig is fully skidded out, leading to fewer rig moves on multiwell programs. “Basically, it allows operators to access the wells at the very back of some platforms without having to move a rig,” he explained. “This allows customers to better optimize their well designs, platform layouts and field developments.”
Another technology is a patent-pending system called PINSAFE, which takes the guesswork out of determining significant wave height when moving jackups onto location. “Our new system also takes into account the capabilities and safety factors of each individual rig design, as well as each location’s sea bottom conditions, allowing us to determine when it’s safe to move on location,” Mr Brady said. This helps to reduce downtime spent waiting on weather, which can be significant in the harsh environments of the North Sea.
These technologies, combined with other innovations – such as an advanced asset management system and condition-based maintenance – resulted in a 99% operational utilization rate in Q1 2017 across Ensco’s global fleet. The contractor also was able to reduce its subsea equipment-related downtime by 80% during 2016.
Looking to the future, Mr Brady said that additional improvements can be achieved by leveraging data. “We’re focused on reducing nonproductive time by developing the means to automatically and consistently record the beginning and end of various flat-time operations. With this information automatically gathered from every Ensco rig each day, we can compare flat-time performance between rigs working in the same region and around the globe. We can then dig deeper to identify best practices, share them with other Ensco rigs and consistently raise our performance across the fleet.”
Robotic drill floor installation this summer
Odfjell Drilling is pushing for a complete transformation of drilling this summer with the pilot installation of a robotic drill floor on the Deepsea Atlantic. The technology, designed by Odfjell subsidiary Robotic Drilling Systems, aims to take new steps to improving both safety and efficiency on the sixth-generation harsh-environment semi, said Kjetil Gjersdal, Odfjell’s Executive Vice President for Mobile Offshore Drilling Units. “Robots are great in that they do exactly what you tell them to do –
nothing more and nothing less,” he said. “We have expectations that we will see a boost of potential for further increasing efficiency, without compromising safety, especially on repetitive tasks,” such as assembling BHAs and handling safety clamps.
The full robotic system uses machines, such as an electric roughneck and electric pipe handler, to achieve precise operation. A drill floor robot is also incorporated, using tools such as grippers, spinners and clamping tools, to make drill floor operations automatic and hands-free. A software platform will be used to control the robots, using high-level commands that tell the robot what
to do, not how to do it. An embedded anti-collision system will allow the robots to operate autonomously. The Deepsea Atlantic pilot project will start off by introducing the drill floor robot on the existing drill floor.
At this point, Mr Gjersdal said that Odfjell has no plans to install the robotic system on any of its other rigs – at least not until testing on the Deepsea Atlantic is complete. “This is a very exciting project,” he said. “We believe that robotic technologies definitely have a place in the future of drilling rigs.”
Besides the Deepsea Atlantic – which is contracted to Statoil until 2019 on the Johan Sverdrup field – Odfjell also has three other owned rigs. The Deepsea Stavanger is contracted to Wintershall Norge until mid-2018. In March, it began drilling the first of six development wells on the Maria field, located in the Haltenbanken area of the southern Norwegian Sea. It is being developed for production in 2018, with two subsea templates at 300-m water depths. The six wells – four production wells and two injectors – will be drilled in two pre-installed subsea structures, with drilling initially expected to last 580 days. However, drilling efficiency has been better than expected so far, and the rig may be finishing earlier than expected, Mr Gjersdal said. All top-hole drilling operations have been completed, and the first well spudded on 20 March.
A third-generation semi, the Deepsea Bergen, had been under contract with Statoil, although the contract has been suspended to allow the rig to commence its contract with Faroe Petroleum. In May, Faroe began drilling an appraisal well at the Brasse prospect, in the Norwegian North Sea. Drilling for a potential second appraisal well later this year will depend on results from the first well.
After completion of the Faroe contract, the Deepsea Bergen will return to Statoil for drilling of the Carmen exploration well. Later in 2018, the rig is contracted to drill an exploration well for Wellesley Petroleum, as well as one high-pressure, high-temperature (HPHT) well, with options for two further HPHT wells, for OMV Norge offshore Norway. Once the HPHT wells are complete, the Statoil contract for one firm well plus four options for three additional wells will be started, likely in Q2 or Q3 2018.
In the West of Shetlands area, Odfjell’s sixth-generation semisubmersible Deepsea Aberdeen is drilling for BP’s Quad 204 development under a contract that extends into 2022. The unit is designed for harsh environments and has a water depth capacity of 10,000 ft.
“I would say we are in a fortunate situation because we’ve managed to keep all our rigs busy,” Mr Gjersdal said, noting that, on an industry level, the North Sea market remains quite difficult. “There are still a number of rigs stacked. Although we are beginning to see some signs of activity picking up slowly, there is no major change for the overall activity level.” DC
PINSAFE is a trademark of Ensco.
Full redevelopment of Tyra to help protect jobs, prolong life of Danish North Sea
In March, Maersk Oil, as part of the Danish Underground Consortium (DUC), reached an agreement with the government of Denmark to conduct a full redevelopment of the Tyra facilities. Tyra is Denmark’s largest gas field, operated by Maersk Oil on behalf of the DUC. The facilities serve as the processing and export center for all gas produced by the DUC, and they process more than 90% of Denmark’s gas production. The agreement is expected to facilitate future oil and gas investments in the Danish North Sea and protect industry jobs in Denmark.
A full redevelopment will restore the current infrastructure, including the gas-processing hub and five surrounding satellite fields, which include Harald and Valdemar, and thereby ensure continued production from the Tyra field. Further, the new asset could enable future production of oil and gas from the DUC license area, as well as third-party projects.
“We have already issued the tenders for the main contracts and will continue to further mature the project as we move ahead,” Morten Hesselager Pedersen, Head of Tyra Future Developmentfor Maersk, told Drilling Contractor. “In terms of the actual redevelopment, you will see the two existing gas-processing and accommodation platforms on Tyra East and Tyra West being replaced by one new processing platform and one new accommodation platform. The four wellhead platforms and two riser platforms will be extended by 10 m, and the current topsides will be replaced by new topsides.”
The Tyra field requires redevelopment due to subsidence of the chalk reservoir, which has led to the platforms sinking by around 5 m in the past 30 years. This has reduced the gap between the sea and the platform decks. As a result, investment is required if the Tyra complex is to continue producing safely into the next decade. “The main operational impact of subsidence is that we, since 2014, have positioned bridge-linked accommodation rigs next to each of the main Tyra platforms during the winter season,” Mr Pedersen said. “These rigs have a higher air gap than the platforms, and therefore the offshore teams will go to these in case of severe winter storms and high waves.”
One of the most critical aspects of redevelopment will be to make sure the new topsides for the wellhead and riser platforms fit completely with the existing jackets and that the jackets are capable of carrying the additional weight and of resisting expected wave impacts. “Another complicated task will be the decommissioning of the two old process and accommodation platforms. They have been optimized and amended over the years in order to meet operational needs, and it will take tremendously detailed planning to safely and efficiently move them,” Mr Pedersen said.
Maersk will pursue technical and commercial solutions for the redevelopment project by working closely with authorities, universities and suppliers under what it calls the Triple Helix approach. “We worked closely with the government to identify a solution enabling continued access to Denmark’s oil and gas resources in the Danish North Sea. We are in close dialogue with DHRTC (Danish Hydrocarbon Research and Technology Center) to develop and embed new technologies offshore, and last year we launched the Suppliers Forum to build value-adding partnerships with suppliers.”
Mr Pedersen added that all 90 existing wells in the Tyra field area will be reused, so no new drilling is expected. Final investment decision is expected to take place by the end of 2017. The shut-in of the Tyra facilities will take place in December 2019, and the redevelopment will be finalized by March 2022, when first hydrocarbons from the new facilities are expected.
“The agreement makes the Danish North Sea a more competitive investment area for oil and gas companies to invest and to develop new opportunities,” Maersk Oil’s Chief Operating Officer Martin Rune Pedersen said. “A redevelopment of Tyra can be a catalyst for prolonging the life of the Danish North Sea. It can protect valuable revenues to the Danish state and Danish jobs – especially in the Esbjerg area.”
Maersk Oil Chief Executive Gretchen Watkins added: “Today’s announcement reaffirms the commitment Maersk Oil has made to invest in the future of North Sea oil and gas and, in particular, in our heartland in Denmark. The recognition of shared value between government and industry in investments like the redevelopment of Tyra are a blueprint for the type of collaboration that will support value creation for decades to come.”