Turning the tide for drilling

The cost of new production wells has multiplied several times over during recent years, putting big volumes in mature fields under threat. But extensive efficiency programmes and new technology could reverse this trend.

| Alf Inge Molde

Photo: Harald Pettersen/Statoil

Photo: Harald Pettersen/Statoil


Many people are concerned about cost developments on the NCS. Their high level not only affects new developments but could also have major consequences for improving recovery from mature fields. That applies particularly to the most important measure in this context – more production wells.

Drilling these accounts for 30-50 per cent of spending over a field’s commercial life, and the bill has risen dramatically in recent years. The average price for a production well drilled from a mobile rig has more than doubled since 2002.

Most of the easy drilling targets have been taken. The bulk of projects awaiting sanction on producing fields involve relatively small volumes compared with new field developments. Many contain less than 2.5 million standard cubic metres of oil equivalent (scm oe) or 16 million barrels.

The NPD has also registered that the operators have had problems delivering the promised wells.

In additional to a dramatic rise in costs, the statistics show that drilling efficiency has declined on a number of fields. Fewer wells are drilled per year from fixed rigs, at a higher price.

The present slump in oil prices from just over USD 100 to around USD 80 per barrel makes the overall picture for production on the NCS look even more serious.


Roy Ruså
Halving and doubling.

”Our attention has been concentrated for many years on getting out the volumes, without thinking too much about costs,” says Roy Ruså, vice president for technology at Petoro. His goal is to halve well costs and double the pace of drilling from fixed installations.
(Photo: Emile Ashley/Petoro)




“Wells don’t just happen,” says Roy Ruså, vice president for technology at Petoro, which manages the state’s direct financial interest (SDFI) in Norway’s petroleum sector. “We’ve underestimated both time and costs.”

Like the NPD, he has devoted most of his time over the past few years to convincing licensees on the NCS to invest more in new production wells on the mature fields.

That is because, despite the many sophisticated methods available to improve recovery, none equal the importance of drilling additional wells.

But progress has been slow – and the clock is ticking. By Petoro’s own calculation, drilling a producer from a fixed installation currently costs four times more than 10 years ago.

Rigs which previously managed three wells a year now do just over one, at an average price of more than NOK 600 million. The cost for mobile units has tripled over the same period.

“If we maintain our present drilling the wells we need before 2060 or 2070,” says Ruså. “The installations will then have been standing for 75-80 years.”

He estimates that 1 000 wells are needed on Norway’s mature offshore fields. “If the recovery target is going to be raised from 50 to 60 per cent, the drilling rate must double.”



The current position is the result of creeping inefficiency, says Ruså. “Our attention has been concentrated for many years on getting out the volumes, without thinking too much about costs.”

Although efficiency has occupied a key place, it has been confined to avoiding faults – in other words, downtime. Great attention has been paid, particularly in recent years, to creating fault-free processes, where everything carries equal weight.

This has been a self-reinforcing process, says Ruså. Ever more detailed requirements are individually well-founded, but less positive collectively.

To find out whether everything really was better before, Petoro has compared the time it took to drill the same type of wells from the seabed to the top of the reservoir on the same field 20 years ago with the present position.

This comparison reveals that 23 of 25 sub-operations take longer now than they did in the 1990s. In the worst case, the increase was 316 per cent.

Ruså believes that ambitious goals are required: “Well costs must be halved on fixed and floating facilities, and the drilling pace on fixed installations has to be doubled.”

Petoro’s comparison shows that this is a realistic target. If it could be done two decades ago, newer technology and longer experience must also make it possible today, says Ruså. That requires the industry to work more efficiently.



Geir Tungesvik


The age of world records is over. Geir Tungesvik, senior vice president for drilling and well at Statoil, wants to work safely, simply and cheaply to improve recovery from the mature fields.
(Photo: Harald Pettersen/Statoil)

Jan Krokeide, manager for drilling at the Norwegian Oil and Gas Association, points out that modern wells are far more complex than those drilled 10, 20 or 30 years ago.

The first horizontal well drilled on Troll in 1989 was 502 metres long, and groundbreaking. “We now drill such wells for kilometres,” Krokeide says.

At the same time, drillers must avoid old well paths and often encounter unexpected pressure regimes because reservoirs are injected with water and chemicals or affected by geological shifts. Plans must then be modified, boosting costs.

Installations are also aging, and old wells must be plugged to make room for more. A new requirement this year is that temporarily abandoned exploration wells have to be permanently plugged within two years.

Where producers are concerned, too, hydrocarbon-bearing zones must be plugged and abandoned within three years if the well is not to be continuously monitored. Such an operation can take as long as the original drilling job – and ties up the same rig.



“The regulations provide a number of cost drivers,” Krokeide observes. “In addition, the companies can have their own internal interpretations and requirements.

“Since things must be as safe as possible, procedures have a general tendency to become more extensive than is strictly necessary.”

Norwegian Oil and Gas runs three networks intended to contribute to experience transfer – the Drilling Managers, Well Integrity, and Plug and Abandonment Forums.

These aim to get the companies to share success stories and challenges, explains Krokeide. “The culture for such sharing has become significantly better.

“The government must also follow up the work it’s initiated itself. In recent years, we’ve had the Åm committee, the Reiten committee and the rig report. These have all established the facts and made recommendations. What’s happened to them?”


Photo: Harald Pettersen/Statoil
Photo: Harald Pettersen/Statoil



Geir Tungesvik, senior vice president for drilling and well at Statoil, says he has been concerned about developments for a long time.

The company has a recovery factor of 50 per cent, compared with an industry average of 35 per cent, and recently set a target of reaching 60 per cent – providing it can be done profitably.

While the oil price has tripled over a decade, Statoil’s own statistics show that costs have risen four- and five-fold without any sign of a slowdown.

Tungesvik has been telling everyone for the past two years that this could not continue, but the rest of the world thought everything would just go on rising.

He says that getting down the cost of drilling and downhole activities would mean more wells and thereby improved recovery. If the negative trend continues, more oil will stay in the ground. It is that simple.

The mantra for Statoil’s technical efficiency programme (Step) is finding best practice, simplifying and working more intelligently. A 15 per cent improvement is the target for this year, and 25 per cent in 2015.



So far, for example, Statoil has needed perhaps three targets to justify a new well. Encompassing all these has resulted in very advanced designs, which take a long time to complete and carry a high risk of failure.

Tungesvik’s answer is to drill to one target, then implement sidetracks to each of the others. Cheaper, more intelligent and simpler. The age of setting world records is past.

“We’ve seen that it’s straightforward to drill a horizontal section 1 500 metres long through a reservoir. Beyond that, the failure rate is high.

“We might get more out of the reservoir if we drill for 1 700 metres. And if we’re going to do that, we might as well continue to 2 000.”

But what happens if the well collapses and the work has to start all over again? Must a well be 1 700 metres long or nothing, or would 1 500 be good enough. Does it have to be so complex?

“People were very satisfied when they finally managed to deliver the complicated well, even though it perhaps cost more than planned,” says Tungesvik. “We must find the right balance between investment and present value.”



The last crisis to hit the oil industry was in 1998, when prices dropped dramatically. Everyone understood that change was needed, with simplification and increased efficiency as the recipe.

Tungesvik wants to recreate that position now. But health, safety and environmental (HSE) standards must be maintained. Operations are much safer than they were in 2000.

“Working efficiently also means working safely,” he says. That calls for good plans where everyone is familiar with the job, the procedure and the equipment, and understands the risk.

Tungesvik is concerned to turn every stone, including contract forms: “The supplies industry has been challenged to come up with alternative forms of cooperation to get down costs.”

That involves standardisation of equipment and solutions, and Statoil is also keen to test new ways for operators and contractors to collaborate.

“My goal is to get down costs and drill as much as possible,” says Tungesvik. “Those who order special and difficult wells are now told that they’re too expensive. It’s no longer acceptable.”



Planning and execution are one factor. Another is technology, notes Sigmund Stokka, head of the Drilling and Well Centre for Improved Recovery (DrillWell).

This Stavanger-based body is one of the country’s Centres for Research-Based Innovation (SFI), financed by the Research Council of Norway and the industry.

Together with the International Research Institute of Stavanger (Iris), Sintef Petroleum, the Norwegian University of Science and Technology (NTNU) and the University of Stavanger, Stokka seeks new technical solutions to improve NCS recovery.

“Although drilling operations are very similar to the way they were 50 years ago, much technological development has occurred,” he says.

The bit has improved, new methods mean the reservoir can be hit more accurately, well control and integrity are enhanced and more specialised equipment can be obtained.

Although the technology is available or just around the corner, however, the industry suffers from inertia. “This is a conservative business,” Stokka observes.

People are afraid of making mistakes. When each well must justify new technology, it is often easier to opt for something known than to take a risk. Some companies run campaigns, which is positive – but not enough.



A report just issued indicates that technical innovation could reduce annual drilling costs on the NCS by NOK 20 billion or 20 per cent within a few years.

This finding comes from OG21, Norway’s national technology strategy for the petroleum industry, which is mandated by the Ministry of Petroleum and Energy.

It represents a collaboration between oil companies, universities, research institutes, suppliers and government agencies.

Work on the report, with Stokka as one of the contributors, has been headed by Dag Breivik, drilling manager for Norway at oil company OMV.

“The challenge isn’t day rates and that sort of thing, but delivering wells at all,” says Breivik. “It takes too long.”

OG21 identifies five technologies with a particular potential to enhance drilling efficiency and save money, including steerable liner drilling.

The others are managed pressure drilling, expandable casing and well equipment, high-speed downhole communication during drilling, and automated and autonomous systems.

Many of these solutions are already on the market and tested, but the companies have failed for various reasons to exploit their potential. Other technologies will soon be available, too.



Drilling a well costs NOK 5-10 million per day. Cutting execution time by 10 days would accordingly save NOK 50-100 million per operation, Breivik observes.

“It’s important to stress that none of the technologies cited will necessarily achieve that alone. But combining several would have a big impact and give the industry more tools.”

The OG21 report also emphasises that the government has a clear role in supporting technology development and piloting, while companies must eliminate requirements which lock in old solutions.

Breivik invites oil companies, rig owners and suppliers to sit down to a collective discussion on the improvement potential and the way obstacles can be removed.

He is well aware that a lot of commitment and collaboration is needed to get everyone concerned to understand what the new technologies involve and what they could mean.

Risk is also balanced against short-term gain, he observes. “But this isn’t something you win at the level of the individual well. It must become part of the standard.”


Resource overview for Norway’s 25 largest oil fields – potential for improved recovery



Mads Grinrød

New ideas.
Mads Grinrød retired as Statoil’s head of drilling and well in 2007, after 35 years with the company. Simplification and efficiency can be pursued to a point where nothing more is to be gained, he says. His present job involves the continuous motion rig (CMR), a completely new concept for fully automated drilling which cuts costs and risk.
(Photo: Emile Ashley)


Industry veteran Mads Grinrød notes that simplification and efficiency can be pursued to a point where nothing more is to be gained. “Then you need a new technology, a game-changer.”

Retiring in 2007 after 35 years with Statoil, the company’s former head of drilling and well shares worries about the number of wells being drilled on the NCS.

He is now working with the continuous motion rig (CMR), a new concept which – put simply – comprises a fully automated unit with two systems which take it in turn to rotate the bit.

Allowing new drill string to be made up while continuing to drill ahead, this solution offers many advantages over existing technology.

At present, drilling has to stop during tripping, and for 10-15 minutes every 30 metres to extend the string. Circulating mud continuously avoids these halts and cuts pressure variations.

Drilling with nobody on the drill floor also provides an HSE benefit and saving in itself. Analyses show total cost cuts of 20-25 per cent compared with existing technology.

“These are conservative figures,” Grinrød emphasises. “We believe the potential is even greater.”



The CMR concept has been developed by West Drilling Products, which is now planning a full-scale rig alongside the Ullrigg test facility at Ullandhaug in Stavanger.

Financed by West Group, Statoil, ConocoPhillips, Shell, the Research Council and Innovation Norway, the aim is to have everything in place during the first half of next year.

Asked when he will be ready to deliver a finished product, Grinrød says this can done in late 2016 if he gets in an order now.

But he is keen to see how the system works. There is no assurance that the equipment will function immediately in the way it does in simulations. But the biggest challenge is to find an oil company willing to take the first step and to devote the necessary time and money to bring a new solution into operation.

Grinrød is well aware of the industry’s conservatism, and says it used to be better at trying new things. The NCS was known precisely for that.

After 2000 in particular, however, the industry has become more wedded to proven technology. Everything is more bureaucratic, and nobody wants to accept risk.

But the answer to the sharp rise in costs on the NCS will be to implement new solutions. A commitment is required, and must be made swiftly.


Regulation not to blame


Photo: Harald Pettersen/Statoil

Photo: Harald Pettersen/Statoil


Nobody has been able to identify which special Norwegian rules might push up offshore costs, with the exception of a few well-known requirements for personnel rest and restitution.

Based on a comparison with UK regulations, this conclusion appears in the latest annual Safety – status and signals publication from the Petroleum Safety Authority Norway (PSA).

“Norway’s offshore regulations are constantly being challenged in cost/benefit terms,” the article notes. “Since the present rules came into force in 2001, however, nobody has been able to identify which of them might make operations more expensive.

“Nor has it been possible to demonstrate that any significant difference exists between the regulations and those in the UK – which Norway often compares itself with, for natural reasons.”

Possible differences between the NCS and the UK continental shelf are often attributable to differences in enforcement and practice, observes Anne Vatten, the PSA’s director of legal and regulatory affairs.

“We’ve asked the industry on several occasions since 2002 to provide specific examples of cost-enhancing requirements which haven’t already been identified. We haven’t received any response so far.”