Drilling advances

	Vol. 232 No. 6
JIM REDDEN, CONTRIBUTING EDITOR

A new slant to what constitutes drilling efficiency

The next time you pick up a brochure touting a new technology, check out how soon a mention of drilling efficiency pops up. The creators of nearly all drilling technology sales pieces, myself included, are quick to point out how the gizmo they are marketing will “improve,” “enhance” “optimize” or otherwise render to its user the most efficient drilling operation the oil field has ever seen.

That particular term has become a boilerplate in sales pieces, and, frankly, with good reason. After all, drilling efficiency is the Holy Grail of the exploration industry. However, these days there seems to be some disagreement over what barometer(s) a drilling team should use to measure whether it’s constructing an eventually useable wellbore in the most efficient manner.

Historically, the definitive criterion was to reach TD either at the lowest cost per foot or at the highest possible penetration rate, with zero safety incidents. Unquestionably laudable objectives, they do not necessarily determine overall drilling efficiency, and in fact some say that unbridled devotion to “fast and cheap” may even prove detrimental. Remember, the objective is to make a well and not just drill a fast hole that is below budget. If the drilling team is charged with staying within a prescribed cost per foot or the bonus structure specifies that it drill the fastest well in the field, human nature may ultimately take control and lead to the cutting of corners that could end up damaging the project’s most important asset: the reservoir.

Minimal downhole nonproductive time, likewise, has long been held as a decisive performance marker. However, it’s been said that even that indicator has flaws, because some drillers simply won’t report it. That may well be true for low-cost onshore and turnkey projects, but with today’s offshore rig rates, spending two days to remedy severe lost circulation and not making new hole would be a tad difficult to keep under wraps.

Of all the widely used indicators of an efficient project, speed may be the most misleading and potentially counterproductive, industry consultant E. W. Merrow told a standing-room-only session at last month’s Offshore Technology Conference in Houston. “As an industry, we care about speed above all else, even if it doesn’t work,” said Merrow, president and CEO of Independent Project Analysis. “We want everything done fast. Certainly speed is good, but we need to know how to be fast.”

Perhaps one of the best illustrations of knowing how to drill quickly and efficiently can be found in the Gulf of Thailand. I became aware of the exploration prowess being applied in Thailand during an early 2001 visit to Bangkok to prepare a technical paper on a new lime-free oil-based mud developed specifically for then-Unocal’s slimhole drilling program. The operator considered the mud formulation its best option for drilling and logging some of the world’s fastest wells in the gulf, where high bottomhole temperatures and invasions of CO2 and other corrosive gases presented myriad operational and economic problems.

At the time, Unocal credited the new drilling fluid, as well as the switch to 4½-in. slimhole wells, PDC bits and steady improvements in drilling practices, with its 65-day reduction in average drilling time per well. The exploration philosophy Unocal developed in the Gulf of Thailand continues today, after the 2005 Chevron acquisition, says Kimberly McHugh, Chevron drilling and completions manager for Mid-Continent/Alaska. She spent eight years on the Thailand drilling team and told the first-quarter 2011 meeting of the Drilling Engineering Association (DEA) in Houston that many of the lessons learned there are being transferred to Chevron’s more mature onshore operations within the US.

These days, McHugh said, Chevron is safely drilling functional 12,000–13,000-ft wells in the Gulf of Thailand in an average of seven days from spud to perforations. And, she emphasizes, with bottomhole temperatures of 350°F, highly fractured structures and pore pressures of 11–12.5 lb/gal equivalent mud density, these are far from cookie-cutter wells. Nevertheless, they are in many ways treated that way.

“What we did was capitalize on the commonality of the wells and standardized our drilling operation there,” McHugh said. “The idea is not to always be drilling new wells, but actually treating the drilling of the wells as a repeated process that can be optimized.”

Optimization, she said, lies not so much in new technology, but rather in a thought process where drilling teams demand to be better and have no fear of failure. “Our drilling teams in Thailand are always thinking out of the box and looking for new ways to take wells off the critical list. But, to succeed, we had to be willing to accept failure.”

In Thailand, she pointed to logging as a prime example, where a change from accepted wisdom led to an “unbelievable” drop in logging time. “Once we realized we didn’t need the perfect wireline logs, but just needed to examine the trends, we found we could log 6,000 ft in six hours and actually log while drilling the next section.”

As for costs, she said the systematic approach has reduced the number of casing strings used from four to three, with drilling costs dropping appreciably. Early in the process, she said drilling costs dropped from $2 million to $600,000 per well.

There can be no debate on the contributions new technologies have made to promote whatever one defines as drilling efficiency. However, as illustrated offshore Thailand, sometimes the best advancements are those that arise between the ears.