Drilling advances

Vol. 233 No. 6

SPE confab looks at detecting, relieving pressures

At least one presenter at an SPE drilling symposium in Houston believes the arrival of newbuild drillship Pacific Santa Ana in the Gulf of Mexico signals a new era for deep-and ultra-deepwater exploration. “We now have a frontier that a lot of companies are looking into, and investing heavily in, and that’s dual-gradient drilling,” said Alan Clarke, director of NOV’s Pressure Drilling Systems. “At some point, this is probably going to be one of the primary methods for exploring the ultra-deepwater prospects we have today.”

That point begins in a yet-to-be announced, ultra-deepwater block, where Chevron is finally about to unveil the dual-gradient drilling (DGD) technology that it has been fine-tuning for nearly four years with the help of GE Oil & Gas and Norway’s AGR Subsea Inc. In a nutshell, as its name implies, DGD, unlike its single gradient counterpart, introduces inactive fluid into the riser with a seawater-equivalent density of 8.6 lb/gal. Weighted mud only comes into play from the mudline down. Consequently, Chevron says well designers and drillers are able to more closely match formation pressures and strengths to what Mother Nature laid down and essentially removes water depth from the equation.

The long-awaited commencement of Chevron’s experiment was but one of the advancements in well control for offshore and deepwater environments explored during the annual SPE symposium.  Presentations embraced everything from new, real-time pressure prediction methodologies to an automobile-like dashboard indicator that forewarns the crew of a potential BOP fitness problem.

While DGD’s well control benefits are obvious, Clarke says the emerging technology may prove to be the industry’s most favored technique for accessing reserves in the stingy deepwater and ultra-deepwater environments. “Of course, safety is the number one concern, obviously. The reserves in these ultra-deepwater prospects will be extra-challenging, and dual-gradient drilling is one of the better ways to manage safety. But, in some parts of the world, we’ll be looking at utilizing this, strictly because of the geological challenges and not just because of the particular reservoir pressures.”

Regardless of the reasons, Clarke says DGD may already be fostering a cottage industry more than anxious to lend a supporting hand. “If you look around the industry today, a number of companies are coming out with new technologies to target this market, because it’s a high-dollar market and, at some point, is expected to be a relatively high-volume market.”

Then again, any new technologies that can keep the lid on unwanted pressures may bring a mother lode to their developers. Clarke pointed to studies showing the costs of non-productive time (NPT) being 10% to 25% of a well AFE, with 40% of that related in some way to pressure issues.

BOP dashboard. While DGD focuses on keeping pressures under wraps, some of the technologies discussed at the SPE symposium are concerned with providing early warning that a potential problem is afoot. One of the more unique items is a technology introduced by BP that anyone driving an automobile can appreciate. Essentially, the technology functions much like a warning signal that lights up on a vehicle’s dashboard to let the driver know it’s time to head to a service facility. Jim McKay, BP drilling engineer, said the technology that the operator has developed alerts the crew that the BOP may not be functioning up to par.

He said that like a vehicle, the BOP dashboard is a warning device, not necessarily diagnostic. It relies on levels of system redundancy to advise that a BOP performance or “health issue” may exist. “A BOP’s health is critical to ensuring that it works as designed. A real-time BOP dashboard can improve communication between operations personnel, rig contractor, subsea engineers and the original equipment manufacturer (OEM) to assess potential BOP health issues,” McKay said.

Meanwhile, Diego Sanchez, a product manager for Halliburton’s Digital Asset Service, said work is underway on developing a method for operators to better monitor pressure barriers and ensure compliance to API recommended practice 96, covering deepwater well design and construction. While API RP-96 is targeted specifically to the Gulf of Mexico, Sanchez added that “many operators are interested in its implementation for global best practice deployment.”

Neil Cardy, Baker Hughes product manager for Wellbore Integrity Solutions & Advanced Logging Services, said integrated, real-time pressure prediction methods are at the heart of many new well control-oriented developments. “Real-time pressure prediction has become a vital service to assist drilling, particularly in challenging environments,” he told the symposium.

Any discussion of pressure eventually gets around to industry standards, managed pressure drilling (MPD) and underbalanced drilling (UBD). Paul Fredericks, marketing and technology manager for Schlumberger’s Dynamic Pressure Management, presented a case-specific examination of how automated MPD was used to control bottomhole pressure (BHP) and equivalent circulating densities (ECD) in the highly depleted Gulf of Mexico Amberjack field. In early 2010, Stone Energy was attempting to revive development of the mature field, where two sidetracks were drilled 10 years ago under taxing circumstances that included depletion, a reduced fracture gradient, unstable wellbore and ECDs that were out of control.

“Controlling the BHP and ECD with automated MPD allowed Stone Energy to reach its planned targets in significantly less time than previously possible, and avoid the wellbore instability and well control events that occurred frequently in previously drilled offset wells,” he said.