Offshore in Depth

Now that onshore activity is gaining momentum, shale is back in the headlines. Operators are flocking to acquire Permian acreage, and Apache’s potentially huge Alpine High discovery could offer opportunities for drillers and service companies. Meanwhile, the offshore rig count remains anemic, and fewer than 20 major deepwater projects were approved worldwide in the past two years.

At last month’s CERA Week in Houston, a Royal Dutch Shell executive told Reuters that his company’s objective had shifted from wanting “to be the best in deep water” to wanting “to compete with shale.” Other operators have shifted their priorities from deepwater exploration to unconventional development. ConocoPhillips announced its pullback from offshore exploration in 2015. Marathon shifted offshore spending to shale plays in 2016. Chevron set a goal of producing 25% of its oil from shale plays within 10 years.

Break-even price not the whole story. Data published by Rystad Energy show that the break-even oil price for new shale and offshore projects is roughly the same, at $56 to $59/bbl. But the magnitude of the commitment for deepwater projects is much greater than for shale. While offshore reservoirs are more prolific, exploration risk is higher. Project timelines are longer, so offshore players have less operational flexibility. Offshore projects are more complex, with difficult logistics and more costly infrastructure. From a financial perspective, deepwater projects require comparatively huge investments, take twice as long to reach payback, and generate lower average returns than shale field developments.

Operators’ responses. Operators’ first responses to the oil price collapse were to slash E&P budgets and extract large cost concessions from equipment and service suppliers. Pad drilling of multiple wells, with similar designs and longer laterals made shale development more efficient. Together, these steps enabled onshore operators to reduce opex by 30% to 40%. Offshore operators have reduced their opex, too, but only by 10% to 20%.

While service companies endured massive layoffs, offshore contractors experienced outsized suffering, caused by decimated offshore budgets and the poorly timed arrival of newbuild rigs. IHS Markit reported a 6% drop in rig supply, with 70 units retired from the end of 2015 to the end of 2016. Rigs under contract fell by 116 during the same timeframe. Hercules, Paragon and Vantage all filed for bankruptcy in 2016.

Simplification on Mad Dog 2. Oil companies also have re-examined the designs for major offshore projects, to reduce costs substantially. BP stopped work on its Mad Dog 2 project in 2013, before the oil price collapse, when cost estimates reached $22 billion. Revised plans, approved in 2015, replaced the initial SPAR with a semisubmersible production platform, a simpler design with a budget of $10 billion for the facility to handle 140,000 boed of production.

Why not standardize? Despite decades of work by API, IADC and ISO, industry standards haven’t done much to reduce costs. Offshore project costs have been astronomical, because of the demanding environment, and also because most surface facilities and subsea installations have been custom-designed for each application.

Several joint industry projects, like those spearheaded by DNV GL, ABS, and the International Association of Oil & Gas Producers, are focused on standardization of offshore facilities, components and processes, with the potential of reducing offshore capital costs 30%.

Where standardization has worked. On Mad Dog 2, BP saved millions by standardizing procurement specifications, which reduced administrative cost and engineering time, and shortened the major component procurement cycle from a year to less than six months.

In addition, two other GOM projects, and one in Saudi Arabia, demonstrate the benefits of standardization. At its Delta House floating production system development, LLOG Exploration leveraged standardization to produce first oil in just three years after construction began, compared to five to eight years for similar GOM projects. Standard designs were utilized from the early stages of engineering, including material and equipment selection. About 85% of the platform’s topsides used standard components.

Anadarko took the “design one: build two” approach on its Lucius and Heidelberg truss SPAR production platforms. Because Heidelberg was an exact copy of Lucius, Anadarko reduced fabrication man-hours and engineering time more than 20%.

In the Middle East, Saudi Aramco standardized the design of wellhead platforms to be used in all of its offshore fields. With this standard design, the company could procure bulk materials and long lead-time equipment in advance to improve efficiency at the fabrication yards. The standard design enabled fabrication of multiple platforms in parallel tracks, and provided Saudi Aramco the opportunity to establish a fabrication yard in the kingdom.

Deepwater oil will be needed. Cost-cutting and standardization won’t make every offshore project competitive with onshore unconventional wells. Keep in mind, however, that faced with the global, annual depletion rate of 5 MMbopd to
7 MMbopd, the world economy will need the oil from deepwater reserves. And, as a Murphy Oil executive pointed out during CERAWeek, conditions may be right for an increase in offshore investment. With lower costs for marine seismic, floating rigs, equipment and services, as well as less competition for offshore licenses globally, operators may have a two-to-three-year window to capture cost efficiencies in the market. 

About the Authors

Ron Bitto

Contributing Editor

Ron Bitto has more than 30 years of experience as a technology marketer and writer in the upstream oil and gas industry. RON.BITTO@GMAIL.COM