Time for an intervention

Well intervention spending has been hit harder than other areas, but it is not due to a lack of opportunities. Elaine Maslin reports.

Island Offshore’s Island Frontier. Image from Island Offshore.

While well intervention spending has been hit harder than average industry cuts, the opportunities are still there, not least from mature North Sea assets.

But, companies need to have the right attitude, processes and resources in place to achieve what could be double digit percentage increases in production. They also need to increase well intervention intensity and use a broad range of tools to benefit the most, says Dan Cole, general manager, energy insights, McKinsey & Co.  

It’s a message that hasn’t gone unheeded by Statoil, which has a dedicated well intervention team working across its assets. For the past two years, the company has done an average 48 operations a year, with results to show.

Overall, well intervention has been having a tough time of it, however. A third of the cost has been taken out of the sector since its peak in 2014. Spending levels are the same as they were seven years ago, Cole says, who was speaking at Offshore Network’s Offshore Well Intervention Europe Conference in Aberdeen. North Sea well maintenance spending has seen an even greater decrease, down 43%, from $1.3 billion in 2014*.

“Could it be the opportunity is not there? Absolutely not,” Cole says. “We have been at US$50/bbl or so for a year, more or less, and there are signs investment is starting to pick up. But, he adds, it is hard to ignore the backdrop.”

Opportunity knocks

What is the opportunity? Cole points to the number of shut-in wells, relative to their maturity, measured by water cut. “There are more shut-in wells as fields become more depleted and have higher water cut,” Cole says. “One in five depleted wells are shut-in, some permanently. But, if some could be restored to a level similar to [comparable] onstream wells, you could very quickly get some good production numbers. From a rough calculation, you could get to a couple of hundred thousand barrels of oil equivalent a day production [across the North Sea].”

Production losses, i.e. maximum production capacity compared with actual production, also point to potential. McKinsey categorized production losses into two categories: reservoirs losses – where a well is not producing as expected, maybe due to mechanical impairment, sand inflow, lack of pressure support, etc. The second category is losses incurred due to testing and intervention work. 

“From 2008-12, the amount of losses incurred increased year on year and peaked in 2012 (partly driven by the Elgin Franklin well control incident),” Cole says. “Since then, every year has seen fewer losses. The share of the losses has also moved from reservoir losses to losses due to testing and intervention work, which is encouraging to see.” The data suggests companies are doing more.

Better benchmarking

Through experience and benchmarking, the industry now also knows more now about what good and bad well work and reservoir management looks like, Cole says. It’s been shown that when two operators with similar assets are compared, the one which performs more interventions and with a wider range of intervention tools and techniques sees greater production increases than the other. 

In a comparison of two operators, one who intervened in one in 15 wells and the other one in three, McKinsey found that the second had 9-10% increase in production, compared with 2% on the first.

“Consistently, operators with higher levels of intervention and production use a broader range of intervention tools,” Cole says. “Add a broader range of tools and more intensive intervention levels drives overall better performance around well intervention and reservoir management.”

By seeking additional recovery, restoring shut-in wells, improving reservoir management, increasing the ratio of water injection and doing infill drilling could bring $70-350 million additional returns in the first year, Cole says. Indeed, he adds that he’s been recently talking to operators that have been getting 5-7% increases from wells that are years and even months from their cessation of production date.

Previous work the firm has done has shown that well intervention can give higher – and faster – rates of return on investment. “We found, as a portfolio activity, intervention stacked up very well against drilling on payback time, and also on overall returns, at about 1.5x better then drilling,” Cole says. 

Organization matters

McKinsey has also looked at the difference between companies with successful intervention programs and those that are less successful.

“Typically, the difference between the good and the not so good are: differences in technical systems, i.e. the process side; the organization and how it is organized; and the philosophy or attitudes towards the activity,” Cole says. “Making sure there is a process in place, identifying the opportunities and getting them through the operation, performance tracking and a good way to transfer knowledge between jobs that go well and those that fail,” all help to put the process in place, he says.

“It also matters, having an organization lined up around this, and you need clear responsibilities, key performance indicators and targets as resources – cash and capability.

It is also important that they [decision makers] understand this is a core part of the business and considered at the top level. We know some interventions fail and some are extremely successful.

“The success rate overall is more than 50%, but people remember the ones that fail. That needs to be challenged.”

Poor plant reliability and poor execution of interventions also results in poor performance in this area, he says. “To get this activity humming, you need all of the cogs to work,” he says. The North Sea industry could also learn from outside Europe, including the way onshore North America operators “ruthlessly” approach their wells.

*Based on data from across 50 assets in the Norwegian, UK and Danish sectors of the North Sea.

The newbuild Island Navigator. Image from Rolls Royce.

Island Offshore looks to next gen

Norway’s Island Offshore is as aware of how tough the market is as any other company. But, the market isn’t stopping it from pushing ahead with the newbuild Island Navigator, due to be delivered from Kawasaki Heavy Industries in January 2019.

The firm has three other LWIVs. These include the second generation Island Constructor (built in 2008), which works in the UK and Norway; the Island Frontier (built in 2004), a first generation LWIV; and Island Wellserver (2008), a second-generation vessel, which works for Statoil in Norway. The latter two were laid up through winter and brought back into service for the improved weather when operating times were more favorable.

This is part of the reason that the fifth generation DP3, UT777 design Island Navigator is under construction. The Island Navigator will offer greater capability.

Demand for higher capability and ability to operate in greater weather windows is driving vessel size up, says Tor Erik Grønlie Olsen, operations manager, Island Offshore.

Already, Island Offshore is incorporating pumping capability with a 2in hose and 2in breakaway connector on its LWI package, with 8-10b/min pumping capacity, he says.

“What we are meeting now is pumping jobs that are high-rate and high-volume stimulation jobs in high-permeability reservoirs, so there’s a requirement for larger diameter hoses, which brings challenges,” he says, including how to connect on top of the well control package and emergency quick disconnect systems.

The sleek-design Island Navigator will be 170m-long, and 28m-wide. It will be cheaper to operate, boasts better station keeping and has better deck equipment enabling it to lower items into deeper waters, Olsen says. It will have a 150-tonne active heave compensated subsea crane and accommodation for 91 people.

Future vessels will need to be able to withstand harsher environments and work in deeper waters, he says, where station keeping is an issue. The capability to do open water completion, top hole completion, cementing and pilot hole drilling are all being studied. It could be that future vessels are designed to stay out more than 30 days (currently).

Island Offshore agreed to the contract with Kawasaki for the Island Navigator in July 2015. The Rolls Royce design vessel will be a combined well intervention and top hole drilling vessel built according to Mobile Offshore Unit regulations.

The ice-class (OCE-1B) vessel will be equipped with a built-in handling tower to secure a safe working environment during operations in harsh conditions, and two work class remotely operated vehicles. Its helicopter deck is towards the middle of the vessel, to secure optimal landing conditions in rough weather. The vessel is fully financed through Japanese finance institutions.

It will be able to perform top hole drilling; construction work; subsea installation work; secure wells; trenching, plugging and abandonment work; tower and module handling; inspection, repair and maintenance work; and Xmas tree installation.

“In the near future, we are going to see exciting solutions from several vessel operators on how vessels look,” Olsen says.

In the current market, new vessels not only need to be able to meet demands for higher capability, but remain competitive with ongoing low rig rates. These factors. offer a double challenge to the LWIV fleet. This could be where commercial models could play a role, with ideas for consortia of operators requiring work being set up, with help from the likes of the Oil and Gas Authority in the UK. How far such ideas could be hindered by legal agreements is yet to be seen.

Carbon composite ComTrac

The ComTrac system.Photos from C6.

Archer and IKM Group joint venture C6, set up in 2010, has developed ComTrac system package using a carbon composite rod.

The system comprises a spoolable, 12mm diameter semi-stiff carbon composite rod with electrical cables (up to 10km-long) embedded for communication with downhole tools, which is driven in and out of producing wells by a ComTrac surface unit. The surface unit includes a control/spooling unit and an injector unit and head that can push or pull the rod into or out of the well, and provide well pressure control.

C6 says using a carbon composite rod has advantages over traditional intervention methods, including a low friction factor, high tensile strength, and the capability of power and signal communication with downhole strings of the composite rod. It can also enter pressured wells and has a flexible constant-tension surface rig-up of the deployment system.

This means it can provide logging, perforating, electro-mechanical intervention, and standard mechanical interventions in well depths and well conditions other current rigless conveyance methods cannot. The surface deployment equipment also removes the need for line-of-sight or sheave wheel rig ups and place the maximum tension point within the injector system, enhancing operational safety.

The system has so far been used onshore in the Middle East and offshore in the North Sea, with several runs completed and further operations planned. C6 is also working on a suite of downhole electro-mechanical tools to work with its ComTrac system.

Statoil champions LWI

Statoil’s approach to well intervention has enabled it to run annual subsea well intervention campaigns across its portfolio, reducing operations time year after year.

“We are a large user of light well intervention vessels (LWIV),” says Øyvind Jensen, ‎manager, drilling & well subsea well intervention at Statoil. “We have been using them since 2000 and, over the last couple of years now, we have had 48 different operations using two vessels per year and we think we are the largest user of this service in the world. We have approximately 525 subsea wells in operations and a fairly high demand for performing these services, for improved oil recovery, well work, etc.”

Jensen says that much of the work is reliant on tractor services and includes data acquisition, perforating/re-perforating, zone isolation, installation of insert downhole safety valves, scale removal, installation or change of subsea Xmas trees, well killing or pumping operations, change out of gas lift valves, sleeve operations, and pre-rig plugging and abandonment work, all without diver intervention.

With firm’s 525 wells spread across 27 different fields – and operating units – having a planning organization which communicates with those units enables Statoil to run long term year on year campaigns, Jensen says. It also means there’s more learning, improving performance and reducing time taken to do jobs.

“Five to six years ago, we took around 17 days per operation on a [LWIV]. Last year, we were just a bit more than a week on a job (7-8 days per LWI operation),” Jensen says. On the two vessels Statoil has been using, the Island Wellserver and Island Frontier, days per well have been reduced from 17 and 18, in 2011, to six and just over 10, in 2016, respectively. The average for both vessels in 2016 was 7.8 days.

“The organization is set up just for [LWI] and the key is to cooperate across different licenses. And by working closely with Island Offshore we have solved a lot of issues,” he says.

Jensen is also hoping to expand the scope of what can be done with LWIVs, including more preparation work for plugging and abandonment, handling cement, and open-water coiled tubing. “We are also looking at new kinds of contracts, such as performance driven contracts,” he says.

Vessels that could work more of the year would also be welcome. Currently, Statoil doesn’t do LWI in winter because it’s too expensive – too much waiting on weather. “Year-round operations would need something else in the market than what there is today,” he says. “110m-long is too short for full year operations. We would like to see 150-160m. That could be stable enough through winter.” But, ultimately, it boils down to cost per barrel, Jensen says.