Old fields, new tricks

Elaine Maslin

September 1, 2016

Time and greater understanding makes most people and companies look at projects and assets differently and it’s no different for oilfields. Elaine Maslin reports from Devex.

The Britannia BLP. Photo from ConocoPhillips.

In the North Sea, there are plenty of mature fields ripe for a fresh look, even in today’s low price environment. Taking a new look at oilfields, whether it is because they need a new export route or because past interventions haven’t quite done the trick, was a common theme at this year’s Devex conference in Aberdeen.

BP outlined how it’s brought new life to the Monan field and ConocoPhillips described the epic journey the Britannia complex has been on.

Ugly ducking

BP’s Monan field, a subsea tieback to the Eastern Trough Area Platform (ETAP) was the ugly duckling in the attractiveness stakes last year, until the firm took a step-wise approach to the challenges around bringing it back online. It then became one of the most attractive projects for the business last year, said Marianne McKevitt, petroleum engineer, BP, at Devex. It also become the first time BP retrofitted gas lift technology using a light well intervention (LWI) vessel.

Monan was discovered in the central North Sea in 1990 and started production from two wells, 130 and 131, in 1998. Artificial lift wasn’t originally considered for the field, brought online during CRINE (cost reduction initiative for the new era), and initially it had good stable producers. But, production rates declined rapidly. By 2001, well 130 was lost altogether and well 131 struggled to maintain a stable flow.

Britannia and the long term compression module. Photo from ConocoPhillips. 

By 2014, after coiled tubing interventions in both wells in 2001 and again in 2008, including retrofitting gas lift on well 130, both wells were offline, with downhole safety valves stuck in closed position. “It was going to take significant investment and a number of complex activities to reinstate the wells so it didn’t look very favorable as an opportunity,” McKevitt says.

However, a look at data from well 130, to look at well 131, suggested there was a significant prize making it worth a try. So, the firm took another look on the basis of performing a reinstatement project, including retrofitting gas lift.

“The key issues were: we didn’t understand if we could reopen the downhole safety valve; we had a complex well trajectory to begin with; well access issues – well 130 had history; we were unsure what we were going to see – it was more than 14 years since we were last in the well so there was uncertainty,” McKevitt says. “We needed to assess if well 131 had the necessary well integrity requirements for a change of service to gas lift. We also needed to understand if the well could be configured for gas lift by punching the tubing and setting gas lift straddles as we didn’t have the luxury of side pocket mandrels. We also knew a rig wouldn’t work based on cost. The key to doing this project was doing it off an LWI vessel.”

Reinstating the wells would require: on well 131, repairing hydraulics and de-isolating the well, replacing the subsea control module, retrofitting gas lift and adding perforations to improve productivity; on well 130, the key task was to restore downhole safety valve functionality.

Diagnostics on the well 130 downhole safety valve using a LWI found the issue was subsea and not downhole, so the subsea control module was replaced using a dive support vessel (DSV).

While the operation to add new perforations on well 131 was held up due to solids in the well, contingencies put in place for scale wash and milling helped the project go forward. Gas lift was then successfully retrofitted using a LWI. On the second stuck downhole safety valve, the hydraulics were fixed using a DSV.

“Unfortunately, well 131 didn’t clean up as much as we had hoped, but combining it with the fact that we came in well under our P50, the economics are still favorable, the pay back is just a bit longer,” McKevitt says.

Key to delivering the project was taking a step-by-step approach, managing risk and cost exposure through phasing the project activities and pre-planning contingency options, McKevitt says. Most crucial was being able to retrofit gas lift off a LWI, something which BP had never done before.

The Skandi Constructor, used on the BP Monan project. Image from Helix Energy Solutions. 

Late life planning

The Britannia facility might be moving into a late life phase, but operator ConocoPhillips continues to look for ways to extend its life, aided by a renewed business focus.

Britannia was operated through Britannia Operator Ltd. (BOL) – a joint operating company and the first of its kind in the North Sea – with ConocoPhillips and Chevron as the 50:50 owners. However, in August last year, ConocoPhillips acquired the shares from Chevron, and BOL (now known as ConocoPhillips (UK) Britannia Ltd.), became a wholly-owned subsidiary of ConocoPhillips.

Discovered 41 years ago, Britannia, sitting 200km northeast of Aberdeen in 140m water depth, is a very different asset, said Rachel Preece from ConocoPhillips, at Devex. With asset maturity and increasing third-party processing complexity, both parent companies embarked on an asset performance review in 2015 resulting in the recommendation for a new operating model.

The Britannia field, one of the largest gas condensate fields on the UK Continental Shelf, was discovered in 1975 by Conoco, now ConocoPhillips. Yet, it didn’t come onstream until 1998. It wasn’t until 1990 that the field was confirmed as a single accumulation – by which time some 22 wells had been drilled by multiple operators. The field was named in 1991, in 1994 the field equity was agreed and the field development was approved.

At the time, Britannia was the largest substructure in the North Sea. It had the longest flowline tieback and was the first to use heated carrier bundles to prevent hydrate formation.

The field came online in 1998, via an eight-legged jacket topside. Two years later plateau production was reached at ~800 MMscf/d, meeting some 8% of UK gas supply at the time.

Yet, that was just the start for Britannia. In 2008, the Britannia Satellites (BritSats) project started up, involving the fabrication of a four-legged bridge-linked platform to the main facility, to tie in the Brodgar and Callanish fields, with Enochdhu added in 2015, and the Britannia Long Term Compression (LTC) module (currently the UK’s largest low pressure compression module) in 2014. This year, first production is expected from the Alder high-pressure high-temperature field, a new tie-in.

“Britannia production has exceeded expectations year-on-year,” Preece said. In total, there are now 47 platform wells, plus nine subsea wells on Britannia, three on the Brodgar field, four on Callanish, and one on Enochdhu, with Alder due later this year. But, while ~2.6 Tcf of the 4 Tcf in place in Britannia has been produced, and some plugging and abandonment work started last year, Preece says that there is still some way to the ultimate recovery goal. Last year, production was about 200 MMscf/d.

“As production from the platform declines, we still have some tricks up our sleeve as we move towards late life strategies,” she says. “Our focus is on effective reservoir management and production optimization techniques, including the use of an offshore petroleum engineer to optimize well uptime and LTC.”

There have been plenty of challenges with lessons being learned on the way. The asset spans four blocks and sub-blocks, and without a single operator, it was difficult to find focus for this cretaceous gas condensate development. “Through targeted acquisitions, we reduced the number of co-venturers from over 30 to three, and with our subsurface understanding being key to the asset value, we are now continuing to test new methods to further develop this,” Preece says.

Having a joint operating company meant getting the best at the time from the two international operators. Now, with ConocoPhillips becoming operator and the move to an integrated operations strategy, it has further reduced complexity and succeeded in a 10% opex reduction in Q1 2016, Preece says.

But, the reservoir management strategy continues and the company is still looking at infill drilling and nearfield opportunities.

The Britannia story, like Monan, will continue.