Plaisance: Escalating rig sizes may challenge growth of deepwater drilling

Posted on 30 October 2013

From left, Joe Bryant of Cobalt Energy, Lars Herbst of Bureau of Safety and Environmental Enforcement, John Hollowell of Shell, John Gremp of FMC, Moe Plaisance of Diamond Offshore Drilling and Richard Ward of Baker Hughes.

From left, Joe Bryant of Cobalt Energy, Lars Herbst of Bureau of Safety and Environmental Enforcement, John Hollowell of Shell, John Gremp of FMC Technologies, Moe Plaisance of Diamond Offshore Drilling and Richard Ward of Baker Hughes at the 2013 SPE Annual Technical Conference and Exhibition in New Orleans, La.

By Joanne Liou, associate editor 

Sixty years ago, Mr Charlie became industry’s first submersible drilling rig. It had 46 beds and was able to operate in up to 40 ft of water. That was an astounding depth in those days, Moe Plaisance, vice president, governmental and industry affairs at Diamond Offshore Drilling, recalled. “We could store 974 barrels of mud, and we had a 12-in. BOP with three rams in it manually.” By the time fourth- and fifth-generation rigs rolled out to conquer the North Sea and West Africa, “we’re up to 140 beds, and we’re going to be working 6,000-ft maximum water depths and can hold 10,500 barrels of mud.”

Water depths, as well as rig size, keep escalating, Mr Plaisance said at the 2013 SPE Annual Technical Conference and Exhibition in October in New Orleans, La. He was participating on a deepwater panel session moderated by Cobalt Energy CEO/chairman Joe Bryant. Other speakers were Lars Herbst, Gulf of Mexico regional director, Bureau of Safety and Environmental Enforcement (BSEE); John Hollowell, executive vice president, deepwater, for Shell Upstream Americas; John Gremp, chairman and CEO for FMC Technologies; and Richard Ward, president of completions & production for Baker Hughes.

In 1953, Mr Charlie cost $1 million to build, Mr Plaisance recalled. In contrast, the sixth-generation rigs being built today can cost upwards of $650 million. “They’re capable of working in maximum 12,000-ft water depth, holding 25,000 barrels of mud and have accommodations for 220,” he said.

However, as industry goes into deeper and deeper waters, “we can’t keep building bigger hammers. We are going to have to somehow slim these things down so that we can get our job done.” Diamond Offshore’s Ocean Apex fourth-generation semi, due for delivery next year, cost $370 million. The company is making use of an existing hull from a cold-stacked unit that was built in 1976. The semi will have a maximum hookload capacity of 1,000 tons, a 15,000-psi five-ram BOP, water depth capabilities up to 6,000 ft, drilling depth capabilities up to 30,000 ft, variable deck load of 7,000 long tons and crew quarters for 140 personnel.

From October 2013 to Q1 2015, 17 new deepwater rigs are expected to enter the GOM under long-term contracts, Mr Herbst said. Approximately 10 deepwater projects are moving forward with development drilling activity. He urged industry to ensure not only crew competency but also equipment capacity. “Some of these discoveries (in the GOM) will require new technology by the way of high-tech drilling and high-pressure equipment,” he said. “With deepwater BOP stacks rated at 15,000 (psi), we’ll have to go with 20,000 (psi).”

For Shell, the GOM remains one of the most important areas of growth and returns. “We now operate seven floating structures in the Gulf of Mexico highlighted by the most recent arrival of our latest TLP, the Olympus platform, in the Mars Basin,” Mr Hollowell said. He believes that Shell and the overall industry have built technology platforms and personnel capabilities to operate such deepwater assets. “That’s important because now we find ourselves with the opportunity to extend that track record of success and technical achievement and leverage those people capabilities to new deepwater frontiers.”

Earlier this year, Shell announced a final investment decision on the Stones ultra-deepwater project that will be developed in the Lower Tertiary. Shell also will continue to mature discoveries at Appomattox in the Mesozoic and Vito in the Lower Miocene. “All three plays are uniquely challenging in their own right and different from the Miocene plays that dominate our existing portfolio,” Mr Hollowell said. “To accomplish these types of opportunities, effective partnering with other companies and suppliers will be critical to meet the technical and operating challenges the new frontier will bring.”

From a service company perspective, one of the most important factors to success is long-term relationships with deepwater operators, FMC’s Mr Gemp stated. Collaboration will be key if industry is to deliver 27 million bbls/day of oil by 2020 to respond to increasing demand and declining production. Offshore drilling will provide two-thirds of that, with 10 million bbls coming from deepwater, he noted

“Today the reservoir recovery rates offshore are about half of what they are onshore,” Mr Gemp said. “ To deliver that 10 million bbls per day, we need to increase the reservoir recovery rates in deepwater. Reducing the total costs of ownership will be a critical challenge to the industry.”

In the GOM’s Lower Tertiary, recovery with natural flow is estimated at less than 10%. However, with integrated completions and reservoir management, recovery factors could be increased to more than 20%, Baker Hughes’ Mr Ward said. “We have to develop and integrate technology to achieve these results.”

Baker Hughes has created an integrated project management team (IPMT) focused on complex development projects, using structured systems and engineering methodologies. This team is responsible for designing and delivering a fully integrated completion system targeting a fundamental change in recovery factors, Mr Ward explained. “Since creating IPMTs, we have seen innovation times reduced by over 70%.”

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