Drilling advances

A small Norwegian company says its efforts to commercialize a lightweight all-electric BOP stack throw a light on two of the biggest hurdles in deploying new-generation drilling technologies into the offshore arena: funding, and someone willing to be the first to give them a go.

“The biggest problem we have in this industry is funding and how to move forward,” John Dale, CEO of Electrical Subsea & Drilling (ESD) AS, told the IADC Drilling Engineering Committee (DEC) quarterly forum in September. “Up to now, 60% of the [offshore] development costs are drilling costs, and we need to get that down to 20% to 30%.”

Dale says nailing down a champion can be equally frustrating. “The operator says, ‘it’s not my equipment, so talk to the (drilling) contractor.’ The contractor says, ‘you can talk to us, but if the operator is not with us, we won’t use it.’ It’s kind of a chicken-and-egg situation,” he said.

Circling back to its non-hydraulic BOP, ESD is now focusing on finalizing the machine drawings as it awaits an initial order. Testing and qualification of the electrical actuation and control system was completed in October 2016 and since then, “it has been like sucking blood out of a stone to get funding to continue,” Dale said. Centenarian drilling equipment manufacturer MHWirth of Kristiansand, Norway, took a 20% stake in the nearly seven-year-old company in late 2017.

Prelude to riserless. Dales says the battery-driven BOP knocks about 45% off the estimated 450-metric-ton weight of a conventional 15K subsea stack. Though applicable for land drilling, Dale says the economic and environmental benefits of the new BOP are magnified offshore, where it comes with no water depth restrictions. The absence of a hydraulic system, accumulators and the like not only helps reduce BOP-associated non-productive time (NPT), but eliminates the costs and spill risks associated with BOP fluid, he says. Along with reducing downtime, over its designed 20-year lifespan, the electric BOP saves the estimated $1.1 million/rig spent annually on BOP fluid alone, Dale said.

During the stepwise development program, ESD tested its patented shear ram at 4.2 million lb of force, “way over the cutting capacity we need today,” Dale said. “We just focused on getting sufficient force to the shear ram to cut and close everything within 20 sec. This is a new type of shear ram, with one cigar cutter, capable of cutting 6 5/8-in. tool joints with less than 1.5 million lb of force.”

Moreover, ESD is looking to eventually combine the electric-activated BOP with its newly developed subsea rotating control device (RCD), to advance the industry’s quest to render the drilling riser obsolete. The Norwegian Research Council and Equinor co-sponsored the development of the complementary RCD.

In a comparative analysis of traditional and all-electric riserless drilling systems, Dale said the latter can shave up to 64.6% off BOP-related downtime in an ultra-deepwater well. Specifically, the pre-operational, running, retrieving, maintenance and testing activities of the electric BOP in a riserless marine environment can save upwards of 218 hr, or 9.1 days, in the construction of a well in 10,000 ft of water, he said.

“Beauty contest.” ESD also was among the 11 original equipment manufacturers (OEMs), which not so long ago touted their shear ram technologies before the Drilling, Completion and Intervention (DC&I) Committee of the DeepStar offshore technology development consortium. In a separate DEC presentation, Dave Barrow, Chevron senior advisor for Subsea Completions and co-chairman of the DC&I committee, said the OEM pitches were orchestrated to “reveal the state-of-the-art relative to shear rams on subsea wells.”

“It was kind of a beauty contest among the OEMs for BOP equipment and the new technologies on BOP equipment,” he said. “It actually unveiled a number of very new and very interesting approaches to shear rams, that ranged from decreasing the liability to altogether new ways of shearing pipes. My personal opinion is that some of these are so new that you won’t see them getting implemented on standard drilling BOPs, but they may get implemented for intervention BOP stacks.”

In reviewing current DC&I projects under the umbrella of the 27-year-old consortium, Barrow highlighted the proposed developments of an early kick detection sensor and an insert wireline-retrievable subsurface safety valve. “It’s unusual for Deep Star to sponsor a project that is going to result in a (marketable) product,” said Barrow, referring to the proposed API-certified device, which would fill a technical gap for a “backstop in the event of a failure of a deepwater 15K valve.”

In an encore DEC presentation, Jim Hall, director of the Letton Hall Group, said the idea behind the ongoing development of a fluid density sensor (FDS) is to detect the slightest fluctuation in downhole mud weight that could foretell a kick. Test results of prototype sensors, inserted in the BHA in a simulated static wellbore-like test stand with a variety of mud types, showed a linear density response over the density range, with sensitivity to wellbore mud weight as low as 0.1 lb/gal, sufficient for real-time kick detection. Hall, who introduced the concept at a DEC forum in November 2016, said the sensor would complement PWD tools, which measure the entire annular pressure gradient from surface to the BHA.

Forum moderator Roy Long, Houston-based technology manager for the U.S. Department of Energy’s National Energy Technology Laboratory (NETL), described the concept as a step-change advancement in well control technology. “It would enable you to refine your model, to get a picture of a kick going up the hole, which has never been done before.” 

About the Authors

Jim Redden

Contributing Editor

Jim Redden is a Houston-based consultant and a journalism graduate of Marshall University, has more than 40 years of experience as a writer, editor and corporate communicator, primarily on the upstream oil and gas industry.