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Going off script in the Gulf of Mexico

Output is still rising in the Gulf of Mexico, even if the longer-term picture is cloudier

THE BIG screen version of the 2010 Deepwater Horizon disaster will hit cinemas this autumn, bringing a time of existential angst for America’s offshore oil industry back to the fore. In the weeks and months after the accident, as CNN ran a live feed of crude spewing into the Gulf of Mexico and the government shut down the sector, a recovery in the US offshore seemed distant.

But six years on, the sector has not only moved on from the tragedy but emerged as a relative bright spot in America’s oil landscape. High oil prices and a string of exploration successes saw the pipeline of new GoM projects fill up after the Macondo disaster. Today, those discoveries are yielding new barrels – defying the industry’s worst downturn in a generation.

Last year, eight new fields came into production. In 2016 and 2017, another six projects should follow, fueling a steady output rise that will see GoM production hit record levels in late 2017 or early 2018. Output should reach close to 1.9m barrels a day by the end of 2017, up nearly 400,000 b/d from the start of 2015, helping to offset some declines from onshore shale fields.

Not all projects are going ahead. Some higher cost greenfield operations like Chevron’s Big Foot field have been shelved until prices recover. But many deep-water GoM projects have lowered costs by tying new wells into existing production and infrastructure and cutting engineering and construction costs.

The first new project of 2016 was the Anadarko-operated Heidelberg field. Discovered in January 2009, during the depths of the financial crisis, the 300m-barrel field started producing in January. The project’s relatively low costs made pressing ahead with the field an easy decision for Anadarko, even today. Bank of America Merrill Lynch (BAML) puts the breakeven price for the 80,000-b/d Heidelberg field at around $30 a barrel and operating costs at just $10/b.

Anadarko managed to keep costs down at Heidelberg through what it called a “design one; build two” strategy. The company used the same deep-water Truss Spar platform design for both its Lucius, which came on stream in 2015, and Heidelberg fields. The strategy cut engineering man hours on Heidelberg’s hull by 19% and the system’s topside by a third. It paid off. The January startup was months ahead of schedule.

More to come

The Noble Energy-operated Gunflint field is also expected to start producing in the middle of this year. Gunflint is a two-well development that will be tied back to Gulfstar’s nearby 60,000-b/d floating production platform. Piggybacking onto this existing infrastructure has helped the project break even at $40-50/b with operating costs at around $25/b. Freeport McMoran’s three-well 24,000-b/d Holstein Deep project is another tie-back development due on stream in mid-2016. The company has said additional wells could be added to the Holstein system to lift production to around 75,000 b/d by 2020, though prices would likely need to recover.

Shell’s 2bn-barrel Stones ultra-deep-water field, also due online in 2016, is pushing the boundaries of GoM development. It will be one of the first to use a floating-production-storage-and-offloading vessel in the Gulf’s waters. The 60,000-b/d Turritella FPSO, retrofitted by SBM Offshore in Singapore, will sit atop the Stones field in water depths of 9,500 feet, making it the deepest production vessel ever deployed.

Shell has touted both the cost and safety benefits of the FPSO over the standard platforms. It should allow Shell to avoid the costs associated with building pipelines to the coast, as oil will be shipped from the FPSO instead.

The company has also touted the safety advantages of having disconnectable FPSOs in the Gulf. Scenes of perilously lilting oil platforms are common after major hurricanes rage through the GoM. FPSOs should sail clear of danger.

BAML says the Stones field FPSO development will have similar breakeven and operating costs as the shallower Gunflint operation – around $50/b and $25/b, respectively. If the project works out, it could become a more popular option, especially as more developments further ashore in the prolific Lower Tertiary section of the Gulf come on stream.

In 2017, development will start to slow, with just two major projects due on line – Freeport’s 30,000-b/d Horn Mountain Deep and LLOG Exploration’s Son of Bluto 2 fields. Both will be tie-back developments. Son of Bluto 2 will feed LLOG’s 100,000-b/d Delta House floating production system.

While the production outlook for the next couple of years is bright, the price downturn may bring a drop off in output growth towards the end of the decade. Exploration spending in the Gulf has dried up as companies slash capital expenditures. The rig count has fallen to levels not seen since the post-Macondo drilling moratorium, from an all-time high of 63 in August 2014 to just 24 in mid-April.

A dismal turnout at March’s lease round is another sign that interest in the Gulf has waned along with the oil price.

Tracts across the central GoM saw little interest from bidders, with the round bringing in just $156m on as many as 128 winning bids. The last time a similar amount of central Gulf acreage was put up for auction in March 2014, the round brought in $1.1bn on 320 winning bids.

This article is part of an in-depth series on offshore production. Next article: Plain sailing for Gulf offshore.

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