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Offshore Faces Its ‘Prove It’ Moment

Offshore E&P, particularly in deep water, is not for the faint of heart. Project costs range from the tens of millions of dollars to the billions, and a failed project or underperforming well could prove debilitating to some companies. Additionally, even those companies that are successful in offshore development must maintain a growth approach, particularly to appease investors and analysts. However, as panelists noted during a CERAWeek session focused on deepwater development trends, it’s not particularly easy to replace the hydrocarbons that are being produced.

“Growth is difficult in the upstream,” said Stephen Greenlee, vice president of Exxon Mobil Corp. “Our company has made for some time about 4 MMbbl/d, with a 5% decline on top of that. Just to stay still, you’ve got to replace 20,000 bbl/d of production capacity, which is a lot.”

As Greenlee and his co-panelists explained, offshore oil and gas is facing a “prove it” moment. Kevin McLachlan, senior vice president of exploration at Total, explained that the industry “has to learn from our mistakes” in spending when prices were $100/bbl or more—often with underwhelming results.

The challenges facing oil companies, particularly supermajors, that work offshore are to continue to find large fields, develop them at much lower costs than before and replace significant amounts of production. Development costs have already substantially improved—down to about $21/bbl from $71/bbl, said Torgrim Reitman, executive vice president of development and production international at Equinor, during the CERAWeek session.

More than 50 years after modern development was initiated, the Gulf of Mexico (GoM) continues to be one of the world’s great offshore areas with several recent announcements proving there is still a place for large-scale developments. In November Chevron announced first oil from its Big Foot deepwater project. Discovered in 2006, Big Foot contains resources of more than 200 MMboe and has a projected life of 35 years, according to the company. The project is designed to produce 75,000 bbl/d and 707,921 cu. m/d (25 MMcf/d) of natural gas. And in January 2018, Chevron, in partnership with Total, announced a major discovery at the Ballmore project in the Norphlet play. According to Total, the discovery encountered 205 m (672 ft) of net oil pay—a potentially massive resource.

Shell’s biggest offshore project, Appomattox, is expected to achieve first oil by the end of the year with peak production expected at 175,000 boe/d. Conceived during a period in which oil prices were about $100/bbl, Shell slashed costs for Appomattox by 30% to keep the project feasible in the lower price environment.

To kick off the year, BP announced a major expansion at its Atlantis Field and also identified “significant” oil resources that the company said could create further development opportunities. Phase 3 of the Atlantis project includes the construction of a new subsea production system from eight new wells that will be tied to the current platform. The new system is expected to come onstream by 2020 and produce about 38,000 boe/d at its peak. In addition, thanks to improved seismic imaging techniques, BP has identified an additional 1 Bbbl of oil in place at its Thunder Horse Field. As if those weren’t enough, BP also announced two oil discoveries in the GoM at the Manuel and Nearly Headless Nick prospects, the latter of which is operated by LLOG.

The size of these projects and their financial solvency are indications that the offshore industry can thrive in the current price environment. And as Greenlee noted, they should prove to be the beginning of new abilities.

“I think we need to prove our ability to replicate these profitable projects,” Greenlee said. “Only when we do that will the market be completely comfortable with us being able to create long-term sustainable value with our deepwater exploration programs.”

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Appomattox field comes on stream in GOM

Appomattox field in the US Gulf of Mexico started production ahead of schedule in the deepwater Gulf of Mexico about 80 miles offshore Louisiana. Shell Offshore Inc. operates the field in 7,200 ft of water.

Shell holds 79% interest and CNOOC Petroleum Offshore USA Inc. holds 21% interest. Shell said the Appomattox development is in the Jurassic Norphlet formation, where the company continues exploration.

The Appomattox development involves Appomattox and Vicksburg fields. Average peak production is estimated to reach 175,000 boe/d.

Shell discovered Appomattox in 2010 and Vicksburg in 2013. The Appomattox hull, weighing 40,000 tonnes, is Shell’s largest floating production system.

Royal Dutch Shell PLC made its final investment decision (FID) on the Appomattox deepwater development in 2015, authorizing construction and installation of the company’s eighth and largest floating platform in the GOM

Production came on stream ahead of schedule and under budget, which Andy Brown, upstream director for Royal Dutch Shell, called “a testament to our ongoing commitment to drive down costs through efficiency improvements during execution.”

“Appomattox creates a core long-term hub for Shell in the Norphlet through which we can tie back several already discovered fields as well as future discoveries,” Brown said.

He said optimized development planning, better designs and fabrication, and expert drilling cut costs for Appomattox by more than 40% since 2015.

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BP eyes US Gulf frontier exploration after years of focusing on tiebacks: executive


After years of pursuing a strategy of mostly tiebacks in the deepwater Gulf of Mexico during the recent industry downturn, BP said it will also now begin adding frontier exploration, a top US executive for the company has said.


After the price of oil dropped by year-end 2014 to roughly half its $100-plus/b value just six months earlier, BP found the most economic pursuit in the US offshore arena was to fill its four large production hubs there with new discoveries made within a 30-mile radius and hook them up to the infrastructure, Starlee Sykes, BP's regional president for the Gulf of Mexico and Canada, said late Wednesday.

"We used to be all about growth, and then particularly after the oil price dropped, it was all about returns "value over volume," Sykes said at the Association of International Petroleum Negotiators' 2019 International Petroleum Summit. "We had a lot of opportunities around our hubs which were really good. To find new stuff wasn't necessary."

But now, BP's strategy is not only to keep full all of its four big hubs originally designed to produce large fields - but to resume the riskier but potentially high-reward treasure hunt for more frontier discoveries, Sykes said.

"Now we'll look at exploration opportunities again," she said.


Tiebacks around hubs - which Sykes called "making the best use of what you already have" - is a higher priority than exploration, and can continue for many years. Further exploration around its hubs probably has a lifespan of five to 20 more years, she said.

But BP, which sees great value in the US Gulf, also wants to build and grow in the region. And for that, frontier exploration is also needed to invest for the future, Sykes said.

While returns for tiebacks are higher than for a brand-new hub development because no major new infrastructure is needed, "the hubs attract more tiebacks," so both work in tandem, she said.

The company has already started gearing up for more exploration by stretching its Gulf leasing program. While historically it has been one of the top spenders and acreage acquirers in twice-yearly US government Gulf lease sales, it has been notable in recent auctions.

For example, BP was awarded a cache of 20 blocks nearly a year ago in the Eastern Gulf of Mexico, an uncharacteristic operating sphere for the company. Sykes would not elaborate what BP is chasing there, but said the company was "evaluating" the leases and would pick the best prospects and "go forward with [them]."

In addition, BP has advanced deepwater Gulf of Mexico technology in recent years that has saved billions of dollars in efficiencies and prevented waste, added billions of dollars more of value and made even relatively small fields economic, Sykes said.


Earlier this year, BP trumpeted its proprietary seismic technology earlier this year that allowed it to discover an additional 400 million barrels more oil around its Atlantis Field and another 1 billion new barrels around its giant Thunder Horse complex, both two of the US Gulf's biggest fields.

The company is now amid a Phase 3 expansion at Atlantis, a $1.3 billion project set to come online next year, and recently launched Phase 2 expansion at Thunder Horse South, to be completed in 2021.

But Sykes said the technology has enabled fields of a size, in the past were typically more the province of small independents, to be economic to a company of BP's size. Majors usually chase so-called "elephant" discoveries of 200 million barrels of oil equivalent fields or more, but she said even 5 million-10 million boe may be economic using tools such as Full Waveform Inversion, which allows processing of seismic data in a few weeks that previously would have required a year of analysis.

"Our Manuel discovery last summer changed our view of Na Kika," she said. "We now see more 25 million-50 million [boe] that have the potential to add over $2 billion of value to the asset."

And, BP is participating in two forums that are developing solutions to produce ultra-high pressure/temperature discoveries made years ago which could open up that play in the Gulf, Sykes added.

Currently, about 15,000 pounds per square inch of pressure in Gulf fields is the limit. But the two groups are working on materials and equipment that can withstand the force of 20,000 psi in extremely deep and remote areas of that arena, Sykes said.

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