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BP … making the North Sea work in a $50 oil barrel world

BP's North Sea regional president Mark Thomas
BP's North Sea regional president Mark Thomas

At last November’s Oil & Gas UK share, BP stated clearly that it could do business in UK waters at $50 a barrel, significantly boost production and hit the exploration trail. Six months later, that strategy holds firm, as the major’s North Sea president, Mark Thomas, explained to Jeremy Cresswell.

2016 was not an easy for anyone in the North Sea and, in BP’s case, this led to some pretty big decisions, principally around the size of the organisation.

However, the company also held its North Sea assets up to the light, asking itself whether they fitted into its global strategic vision any longer. It turned out that North Sea actually remained one of BP’s top areas.

“Helped by UKCS fiscal improvements, the North Sea continued to be a place where we thought there was opportunity, where we thought we could get a fair return on our investment and where the opportunities that presented themselves to us were still of world-class quality,” Thomas said.

“We talk about it as one of our top four areas in the upstream business in terms of production, investment quality and with regard to where we want to be.
“If anything, the review reinforced the importance of it to us. But we also realised that we needed to get much more focused on what we wanted to do and what we won’t do in the North Sea.”

This is despite the advanced maturity of the UK Continental Shelf and spectre of large-scale decommissioning accelerating over the coming decade.

Thomas’ view on this dimension is clear: “My job is to minimise the cost of that decom and actually to extend the life of assets and hydrocarbon recovery as long as possible.”

There are four main elements to BP’s UKCS forward strategy. Arguably, the cornerstone to this is the current investment programme through to 2020. This is about new developments like Clair Ridge and Culzean plus, in effect, Quad 204 which came onstream on May 22.”

But that only gets BP to 2020 in terms of growth. What comes after?

Thomas: “In the review we found that we actually had a good plan to 2020. What we became concerned with was that, after 2020, we peaked oil and then production started to drop off. So, as a strategy, we looked at that and said, errrrm, we need to start thinking now (in late 2016) what we’re going to do to try to continue the right level of investment with the right level of production post 2020.

Strategy Leg 1

“The presumption was that we needed to load up the front end … exploration. We acknowledged that, which is why this year we are drilling ourselves or participating with partners in six exploration wells.

“Its’ proper exploration; informed wild-catting. These days we don’t go in without a pretty good understanding of seismic, wells we can correlate to and so-on. This isn’t exploration based on a one in 10 chance; we’re going into something with a one in five or less chance of success.”

The programme is as follows:
• In the Southern North Sea, BP is currently drilling in the Carboniferous with Perenco.
• It will be drilling with Shell in the Shearwater area later this year … the target lies in Triassic geology.
• It has started drilling the Craster prospect West of Shetland with Nexen.
• It will be drilling Jock Scott with Statoil in the East Shetland Basin
• There is the Capercaillie, which is west of Hurricane Energy’s Warwick development
• Then there is Achmelvich in the Greater Clair area, which will be drilled by the Clair partners led by BP.

“We’re looking for the next big new development for us; but there is the potential for smaller discoveries too and, as a result, tie-back options, particularly in the Central North Sea, like Jock Scott,” said Thomas.

In the light of the successes that Statoil and Lundin had in the Norwegian sector of the North Sea with Johan Sverdrup and where they took a different approach to geological modelling and also in the light of Hurricane Energy’s successes West of Shetland, has BP materially changed its approach to geo-modelling that’s built into the planning of these wells?

Thomas: “I would split those. One of the reasons why we’re partnering with Statoil is because of their experience with Johan Sverdrup. They’re bringing that technology … that technical understanding … to the UKCS.

“In the case of Hurricane, I’m taking a wait and see approach. There’s been phenomenal press about its finds but, for us, it’s still too early to tell.
“An extended well test would shore up some of the presumptions that have been made around Hurricane and its Lancaster find.”

The exploration programme is intended to go beyond just the six wells this year.

“We were very successful in the 29th Licensing Round that will have obligations for us in 2019 (possibly 2018 too) and our exploration for the next three years will look significantly different than over the past five or six years,” said Thomas.

Does that mean a sense of adventure has returned to BP’s North Sea business?

“I’d say it’s a sense of necessity,” replied Thomas. “We need to find our next big new developments or we will face a decline post-2020 that isn’t acceptable to us, nor do we think that it’s appropriate. We’re not doing our job for MER UK unless we’re out finding hydrocarbons and we think they’re still there to find.”

Strategy Leg 2

“Leg two of the strategy … where is our next big development?” said Thomas. “Where are the big development barrels. Where are we going to put a significant portion of our capital?

“We believe that West of Shetland is our growth area. We believe there is lot of hydrocarbon for us to go find and develop. In our strategy we said we’re going to have a pretty significant but continuous programme that avoids a spike.

“We want a programme that allows us to fully develop West of Shetland, And whether that be Clair or further work around Loyal and Schiehallion (Quad 204), or around Foinaven, that’s all in the game for us and where we plan to spend the most amount of money.”

In the context of Clair, two years ago at the November 2015 share fair, BP put out an outline of the potential third phase of Clair complete with an outline estimate of overall cost.

Since then the industry has suffered a major slump though appears to be on the road to recovery. Presumably Clair III was kept alive; so what is the current position.

Thomas: “We didn’t put the brakes on; we’re not going to react to cycles of price if we don’t have to. On Greater Clair and Clair Phase III, we’re still in early discussions. Our partners are with us on this and so we’ve had continuous ongoing conversation and technical assessment with our partners.

“We’re yet not prepared to commit; it’s still too early and we still have time. But we’re on a natural progression with regard to developing what we think would be the next big project on Clair. We’re not yet at a major gate (in terms of decision making).”

Thomas emphasised that the Greater Clair Achmelvich exploration was not linked in any way with Clair Phase III. If successful, then Achmelvich would presumably help pave the way to yet further Clair area development.

Given that Schiehallion has been redeveloped via Quad 204, what about its older (in terms of production) Foinaven neighbour. Might it be a redevelopment candidate?

“It’s still viable in terms of topsides,” replied Thomas. “Yes, its old, but we keep looking at it and we still see eight/nine years of real technical life in it. And every time we look at it we seem to extend that out further.

We could easily be looking at a mid 2020s timeframe right now; but every time we look at it we don’t necessarily find a technical issue as to why it (the production ship) couldn’t actually go longer (than the current estimate).

“That said, just like what we’ve done with Schiehallion and Loyal fields, you do come to a point where you think, is there an offering here where we could look at some redevelopment and new opportunities that are currently limited by the infrastructure that we have in place.

“So, we’re looking at that. It’s not our highest priority but I’d say it’s something that we investigate from time to time.”

Strategy Leg 3

Thomas: “To the third leg of the strategy and that is that we recognise that there are still opportunities available to us in the Central North Sea. This isn’t about big projects, but there’s still a lot of value to be had there.

“So, coming back to our exploration programme, there are opportunities to find stranded resources that are near our infrastructure; Capercaillie would be an example.

These are small pools in the 20-50million barrels range; they wouldn’t justify a standalone development but they’re certainly very attractive from a tie-back perspective.

“We look at the CNS as the place where we will have limited investment. But we want to sweep up the opportunities, particularly around ETAP, Andrew, Bruce, Keith and Rhum, to try to maximise utilisation of those assets. We will look at potential ‘ILX’ type exploration and we have put a lot of money into refreshing those assets including Andrew and Kinnoul, put a lot of money into Magnus which is a part of the recent Enquest transaction.

“Bruce, Keith and Rhum have fundamentally changed, not necessarily through refurbishment but because of the fact that the team said we’ve got a huge amount of infrastructure but we have smaller throughput; so it’s about how do we optimise the kit to run at ultra-high reliability with the volumes (of hydrocarbons) that we’ve got. The Bruce, Keith, Rhum assets are working particularly well right now.

“We’ve put almost $1billion into ETAP and we now have a lifespan well out into the 2030s. We’ve just bought into Repsol’s share in the Seagull discovery of which Apache is currently the operator. We’re looking at that as a possible tie-back to ETAP as an option.

We think there are other options for tiebacks too and we look at ETAP as being a key hub of the Central North Sea … one that has quite a long future ahead and which is quite a big generator of value and cash for the company, having invested a significant amount of money into it.”

Strategy Leg 4

“The fourth leg is simply around the fact that how we operate, how we run this business, not just the North Sea but in general as an oil & gas industry which is being run in a very similar to the way we did 20 years ago.

“So how do we learn from the rapid and quite radical changes that have occurred in other industries like the automotive sector, nuclear and mining and bring those learnings into the oil & gas sector.

“How do we modernise and transform our business here in the North Sea using technology?

“For example, how do we drill wells quicker, simpler, more easily and for 50% less cost than we have customarily done? How do we drill wells where, rather than having a drill crew of 86 people, we drill with 30 or 40 people on board.

“How do we use remote monitoring; in fact how do we use remote sensors even for intervention while we’re drilling wells?”

This begs the question as to who BP is co-operating with on this kind of work. For example, Statoil has the full automated drill-floor as one of its key technology projects.

It also raises the question as to what the company has learned to avoid from its own past mistakes, such as large-scale contracting out and apparent over-emphasis on project capex at the cost of operability of which the Andrew development in its original form appears to be an example.

Another appears to be its approach to new technologies development where the emphasis is not on working locally but globally and working directly with global suppliers like Halliburton and Schlumberger and so-on on that.

“So I’d say the learning for us is not to try to do things like develop the person-less drill-floor locally. It’s more efficient and effective when done by our central teams working directly with contractors.”

But what about co-operation with other oilcos?

“We’re in a time where collaboration is probably higher than it has normally been,” said Thomas.

“But we also compete internally; we want to have six exploration wells this year but we’ve had to compete hard to get them.

“We compete with other companies through licensing rounds. But I would assert that collaboration is more effective, impactful, understood and accepted than it probably has been in the past.”

Does that collaboration also include better valuing of people?

After all, during the late 1990s crash that seemed not to be the case with BP leading the way on things like contracting out … getting back to core business.
Again, many jobs have gone in the latest downturn.

“There is a place for us to have gone through that process and outsourced certain services that one could ask: ‘Are they core to producing hydrocarbons?’. Our business is producing hydrocarbons; we’re not an employment agency, we’re not an engineering contractor.

“However, there is an optimum point of what you consider to be an in-house resource and what you can outsource. At one point we even experimented with outsourcing engineering.

“But we produce hydrocarbons and we’re a technical company so you need to have that technical wherewithall.”

So did BP quietly pull certain skills back in-house over a number of years following the excesses of CRINE and the late 1990s oil price slump?

“Yes, we did. I’d say that today that I’m very comfortable that we’re a self-contained business and that we have the right balance between those services that we get from third parties and what is required to actually run the business inside BP. I would say we’re in a good position today around that.

“And you’re right; we have brought back technical resources that at one point we considered outsourcing and actually started to take steps to outsource.

“Bringing those back in-house now is actually the right thing to do and that’s where they are. So we’re a self-contained shop. We can run as is.

“But when it comes to technology development and especially moon-shot type technology development, our lesson learned is that it is more effectively done on a global basis by a central team,” said Thomas.

“As regional president for BP here in the North Sea, I would look to our central function to be developing the technology that we could then apply in the North Sea, such as personless drilling; such as running our operations with more remote control.

“You ask what else has changed in 20 years. What about digitisation of the business and then, once you have data, ensuring the availability of that data and having the ability to process it and find the needle in the proverbial haystack per-se.

“To be able to use digital technology to predict, to simulate, to create stability in an operation; that’s a big deal for use. Just think about the computing capability on your iPhone; it’s greater than some of the servers that we’ve got offshore running our control systems.”

And so back to the oil price and the ability to business at $50 oil, is Thomas really that confident that he can hack it in the North Sea and make decent money for BP’s shareholders?

The answer is a clear yes.

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