Lucky for some

Alpha Petroleum is proving that there’s room for small independents to make their mark in the UK North Sea. Elaine Maslin looks at the firm’s Cheviot field plan.

Image from Centrica.

Some fields get a second chance. For Cheviot, it could be third time’s the charm, under plans by Alpha Petroleum, an independent oil firm backed by private equity firm Petroleum Equity, focused on the UK North Sea.

The field, discovered in 1975, in blocks 2/10b, 2/15a, 3/6a and 3/11b, produced from 1992-1996, and has laid dormant since.

Now, Alpha is planning to deploy the Petrojarl Varg floating production, storage and offloading (FPSO) unit on the field, with first oil from Cheviot and the Peel field targeted for 2019. There are 18 firm and five contingent wells planned. Late September, Alpha contracted Awilco’s WilPhoenix to drill 18 production wells, starting Q2 2018.

“We’ve looked at the problem differently,” says Andy Crouch, Alpha’s CEO. “The issue for smaller companies is getting finance. There’s no point having a good idea if you cannot get finance. We set a target of having full cycle costs from today to decommissioning of less than US$40/bbl, so that the economics are not driven by the oil price but our stand-alone development, driven by strong technical understanding and knowledge and being able to work in a low-cost environment.”

A false start

The Emerald field was first brought onstream in 1992 by Midland & Scottish Energy using the Emerald Producer floating production unit, a conversion of the Ali Baba semisubmersible drilling rig, chartered from Trafalgar House Offshore & Structural.

In-place hydrocarbons were estimated to be 216 MMbbl of oil and 61 Bcf of gas, with an estimated 43 MMbbl recoverable oil by the initial development plan, according to a 1991 Geological Society paper.

But, the field was decommissioned in 1996, due to a high level of water production and low oil prices (since 2009, the Emerald Producer, now called the Northern Producer, owned by Northern Offshore, has been working on EnQuest’s West Don field in the UK northern North Sea). When the field was abandoned, just 8% of the original oil in place had been produced, according to Alpha.

In 2007, ATP Oil & Gas outlined plans to develop the field, initially via a concrete gravity-based platform, targeting 2009-10 first production with up to 10 production wells and two water injection wells.

The concept was later changed to a new design, the Octabuoy, designed by Moss Maritime. It was a semisubmersible floating platform. Peak production was expected to be 35,000 b/d of oil and 60 Mcf/d of gas via 16 wells, comprising 13 producers and two water injectors and one gas producer. First production was targeted for 2014. A hull contract for the Octabuoy was awarded to Cosco Nantong Shipyard, but Cosco discontinued work in 2016, after ATP went into a company voluntary arrangement (CVA) in July 2014, following its parent company, ATP Oil & Gas Corp., filing for a Chapter 11 bankruptcy protection.

The Petrojarl Varg. Image from Teekay.

Fast forward

Cheviot, a Jurassic reservoir, will now be produced via three drill centers (driven by the field size and geometry), at 2.1-3.6km from the Petrojarl Varg. There will be a minimum 18 wells: 13 production wells, two water injection wells and two gas injection wells. The project also includes one production well in the satellite Peel oil reservoir and there are also infill opportunities, says Crouch, who was CEO at Gaffney Cline Associates before becoming CEO at Alpha, and a senior manager at British oil firm Lasmo before that.

There will be a subsequent “simple” development of the Cheviot gas caps and Padon satellite field. In total, Alpha says it is developing at least 55 MMbbl and future gas volumes of 120 Bcf. The firm says the Cheviot facility could also be used as a hub for other nearby discoveries and prospects, which have an unrisked potential of some 400 MMboe

Alpha has had the benefit of the previous production history on Emerald, as Cheviot was known, as well as relatively recent seismic data. “We have done a lot of work assessing different well configurations and the gas and water injection configuration,” says Crouch. “A lot of reservoir engineering work and development work was done to get a firm understanding of what the potential of the field could be under different scenarios.”

A new conversion FPSO was considered, but ruled out early. Instead, the firm looked at what was available in the rental market to see if anything would broadly fit the bill, and then finalize the development plan based on that concept. It might not result in the optimum technical development option, but it’s the more economic development option, says Crouch.

“We have looked at the problem in a different way and how to get to the solution with what is available to us,” says Crouch. “Because this is a redevelopment – it effectively had a four-year production test – we have a lot of good information on the size and productivity and what the processing requirements we need are.”

The Petrojarl Varg, a ship-shaped, turret-moored FPSO, delivered in 1998, was picked. It has 470,000 bbl storage capacity, and 57,000 b/d oil production capacity. Alpha has signed an exclusivity agreement with Teekay to redeploy the 210m-long Petrojarl Varg, which has accommodation for 77 people, and 10 riser slots, on Cheviot, with project sanction expected in Q4 this year and first oil production targeted for 2019. Production is expected to be about 30,000 b/d.

The Petrojarl Varg had been working on Repsol’s (formerly Talisman) Varg field offshore Norway, alongside a wellhead platform. Production at Varg started in 1998 and ended in 2016. The vessel has since been laid up outside Stavanger, Norway, near Intecsea’s Rosenberg yard. A yard for some work (“a lick of paint” and minor process modifications) on the Varg was being finalized in July. Work is due to start next year. Once up and running, Cheviot is expected to have a 10-year field life.

Alpha has taken a similar approach to the subsea umbilical, flowlines and risers and subsea production system packages. “Traditionally, we find a project engineering company to set out specifications and that normally takes quite a bit of time and money and you end up haggling with the contractors,” says Crouch. “We engaged a different way. We had functional specifications for the trees and manifolds.” After a competitive tender, GE Oil & Gas came out on top. “It reduces the interfaces,” says Crouch.

Alpha has an agreement with GE Oil & Gas for it to partner on the advancement of the subsea infrastructure for Cheviot. GE Oil & Gas will also supply the project’s subsea trees, a full control system, three manifolds, flexible jumpers, flowlines, risers and umbilicals. GE Oil & Gas will also provide subsea construction and installation services, and support commissioning.

In addition, GE Energy Financial Services is helping to raise the needed debt financing for the project and is in discussion with Alpha Petroleum with the intention, subject to due diligence, of making a significant capital investment at the time of final investment decision.

Development well drilling is due to start in Q2 2018, with a rig contract expected to be announced in July/August. Eight wells will be drilled before first oil: five Cheviot producers, one gas injector and one water injector, plus a Peel well. Nearby are three other accumulations which could also tie-in to Cheviot, one which is unlicensed and two others which are held by other operators, one with which Alpha has already had discussions.

It’s a repeatable model, Crouch adds. Varg could be reused to produce from other abandoned or and end of life fields where platform facilities are no longer economical. Or another FPSO could be found to do similar work. Tapping small pools is expected to be part of the UK North Sea’s 30th Licensing Round, with quite a few fields “that have been around for quite some time” hopeful of finding an Alpha to come along and change their fortunes.