Shell has been busy at its North Sea Gannet Field. It has drilled its first infill well in 10 years, has been using a hydraulic workover unit for the first time in 10 years, is replacing subsea infrastructure, running a significant well intervention campaign, working on a gas cap blowdown and shooting 4-D seismic to look for further opportunities. What’s significant is that all of this is being done on one asset, which some four years ago was completely shut in. Now, however, following a renewed systematic focus, production from the Gannet asset has been returned to levels not seen since the end of the last decade—and there’s more to come.

Gannet is a cluster of seven fields, discovered in 1969, with about 1,200 MMboe in place. Fields A to D came onstream in 1992, followed by E and F in 1997 and G in 1999. Field A was drilled from the Gannet A platform with all of the other fields being subsea tiebacks. The reservoirs are high quality with permeability in the 100s to 1,000s mD and a bottom-drive aquifer across all the fields. To date, about 500 MMboe has been produced.

The field, by its nature, had a short plateau and by the mid-2000s, new wells were drilled into six of the seven fields to arrest the decline. In August 2011, however, a leak in the Gannet F pipeline saw production shut in at all Gannet satellite fields that used the same type of pipeline until they could be assessed. Then, in February 2013, a pig became stuck in a wax plug in the Gannet oil export pipeline, resulting in the entire system being shut in for 18 months. It was a dark time for Gannet.

“That might have been it for Gannet,” said Cliff Lovelock, senior geologist with Shell. “But we didn’t give up. Our challenge, following the re-establishment of the export route, was to deliver all the opportunities we saw for the field as competitively as possible to attract investment.”

Although the aging infrastructure was proving to be a challenge, Shell had the benefit of production history and a lot of data (reservoir saturation and production test data), dating back to 1992, as well as 4-D seismic to show where the remaining hydrocarbons were and where they flowed as well as where the water was coming from.

The opportunities were there.

“Ten wells were being considered when I joined [in February 2012],” Lovelock said. In August 2014, after new pipelines were installed on Gannet F and the blockage in the export pipeline was bypassed, Gannet was brought back onstream for the start of a new life.

The big expensive ideas were put on the shelf and what you might call “low hanging fruit” became the order of the day.

“We had invested in reinstating the pipeline and getting the stuck pig out. We needed to pay that back and then pay forward. But it wasn’t just about adding volumes; it was doing it cost-effectively, as simply as possible and making the very most of the extensive infrastructure already installed,” Lovelock said.

“It also meant being more realistic when selling projects to partners,” he added. “In the past, this wasn’t the approach taken, and when something didn’t work, confidence was knocked and support for future projects less forthcoming.”

Gannet F

One of the first opportunities was drilling into a part of Gannet F that was untapped but known (it had been identified as a target in 2006 following 4-D data acquisition) and seen to be mobile. The well—the first new infill well on Gannet in nearly 10 years—was drilled in 2015 and delivered impressive production rates at 20,000 boe/d.

That initial success brought with it more confidence in Gannet, and further opportunities are being looked at in F, with 4-D seismic having been shot in summer 2017.

Interventions

A more mechanical piece of work has been reinstating wells on Gannet A through a series of intervention campaigns from the Gannet A facility. When production restarted in 2014, four out of 13 wells were in production, and two of those were impaired. Four of the 13 would not produce again, but five had the potential to be reinstated, Lovelock said. Four well intervention campaigns have been run, mostly using wireline to run new reservoir saturation tests followed by perforations, but also to restore subsurface safety valves and well integrity. Up to April 2017, the campaign had been run significantly under budget and added just over expected initial oil rates overall.

There has been one problem well, which resulted in Shell deciding to bring a hydraulic workover unit onboard Gannet A—a first in 10 years for Shell in the North Sea. The derrick on Gannet A was cold-stacked, and to use it would require bringing a mud package onboard or alongside. A hydraulic workover unit from the firm WellGear was modified and brought onto the platform. The well—which proved challenging by needing to be killed due to a gas well kick and then killed again—had an inoperable safety valve and needed the tree and hanger removed. The tubing was finally removed, the well plugged and was then recompleted earlier this year, according to WellGear’s Andy Black, head of operations U.K.

Gannet C

Another opportunity was a gas cap blown down on Gannet C, which had until then been producing the oil rim. This activity had been planned, as part of the initial field development plan with two wells drilled (but not completed) in readiness. However, to start the blowdown, an alternative production route from the field to the platform was needed for which the team identified an unused pipeline in the existing bundle that could be brought into service.

After successfully showing the unused flowline had integrity, production was brought back onstream. One well has been recompleted, the oil window shut off and the well reperforated to produce. A second blowdown well in the south of the field is due to be completed this year.

“A simple opportunity like that, part of the original field development, was there but enabled from a renewed vigor to make use of existing equipment and avoid unnecessary expensive replacement,” Lovelock said.

Other opportunities

There has been considerable additional work performed on Gannet. A pipeline, similar to the failed Gannet F pipeline, was replaced on Gannet G with a flexible line, at a quarter of the cost of the initial estimate. Production restarted in April 2017 following its shutdown in 2011.

Gannet E—at one time the longest subsea tieback with an electric submersible pump—has been disconnected from Gannet and is being readied to connect to a new host in 2018. The Gannet B pipeline was recently intelligently pigged and following certification of a new corrosion inhibitor is expected to be brought back online in 2018.

It is a great story of systematic recovery, working each project one at a time. By being clear on the minimum functional requirements and making the most of the equipment already in place, the team was able to ruthlessly cut waste and make the Gannet cluster a profitable place to invest. With these guiding principles, the Gannet cluster is producing at rates not seen for 10 years and has a bright future ahead.

References available. Contact Jennifer Presley at jpresley@hartenergy.com for more information.

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