Drilling Advances

An ExxonMobil engineer has a ready comeback for those questioning the firm’s reliance on conventional drilling methodologies to land extended-reach wells more than 9 mi long: “Why try to reinvent the wheel, when we can keep it spinning?”

As operator for the Sakhlin-1 multi-lateral, extended-reach drilling (ERD) campaign in Far Eastern Russia, Exxon Neftegas Ltd. has kept the wheel spinning ever farther for the better part of 14 years. And, even with nine of 10 world-record ERD wells under its belt, the operator says a tweak here and there promises to extend lateral reaches that, as of now, are boundless.

“We haven’t found the limits of conventional drilling,” says Chase Holub, senior drilling engineer for the ExxonMobil Sakhalin-1 drilling team. “When the next well comes up, and we want to go a little bit farther, we pull what we did on the last well, and say ‘we could have gone farther, if we changed this or that.’ So, we do it, and we get there. We’ve yet to run into the scenario where we say, ‘we can’t get there.’”

Getting there, however, means overcoming distinctively formidable, and usually compounding, challenges. These include, among others, friction and drag, drillstring and surface equipment design and circulation issues, related principally to controlling equivalent circulating densities (ECD) and cleaning holes where deep cuttings beds can quickly build up on the low side of the wellbore. Holub made these comments at the IADC Drilling Engineering Committee’s (DEC’s) quarterly Technology Forum in Houston on Nov. 15, appropriately dedicated to “Extreme Drilling.” 

Using among the world’s largest land rigs, the Sakhalin-1 project encompasses largely “abnormal” wells, drilled from onshore locations to target multiple reservoirs in the Sea of Okhotsk, reaching out more recently to a record of just over 9.3 mi. A typical Sakhalin-1 wellbore is constructed with a long, 135/8-in. drillstring with a usually floated 95/8-in. liner, transitioning into an 87–90° inclination going into the 81/2-in. open hole that often is more than 2 mi long. “A lot of times, we have a mother bore with two or three multi-lateral junctions in it, spanning off into different zones in the reservoir,” Holub says. “The idea behind this is that we drill the well once, and we only have to drill the production interval for the different wells, so you’re saving two-thirds of the well costs, and you’re controlling the production through one tree, one wellhead and one piece of surface equipment.”

Challenges aplenty. To compensate for varying stress regimes throughout the wellbore, the wells usually are drilled with tapered 65/8-in. and 57/8-in. drill pipe. Addressing drag and torque on connections is a primary concern, where surface rotating speeds reach up to 90,000 rpm, with connections typically capable of withstanding downhole rates of only 60,000–70,000 rpm. “We actually manipulate the friction factor of the pipe dope. If we make the friction higher on pipe dope, we can actually torque the connection up higher, without the connection seeing that stress,” Holub said.  

Along with addressing daunting downhole torque and weight-on-bit (WOB) transmission issues, the operator also must deal with the combined loading ramifications of cleaning up cuttings beds that quickly build up on the low side of these ultra-elongated wellbores. Continual backreaming of up to five days can instantly morph into over-pull. “The pipe immediately goes from borderline-acceptable, to you’ve snapped it somewhere,” he said. “We go over how to combat this and develop a plan to let the rig know that if I’m rotating at X speed, and pulling at X weight, how is that affecting the drill pipe downhole?”

Engineering drilling fluids to balance wellbore stability and rheolgical control in the face of ECD of more than 5 lb/gal is of particular importance, Holub said. “What kind of flowrates will we drill with for hole cleaning, telemetry and (cuttings) transport? We may say we want to cut rheology, cut PV (plastic viscosities), because we want low ECD, but we need 6-rpm gels to transport cuttings and clean the hole.”

Likewise, in this zero-discharge environment, solids and waste management control is critical, as is reducing unmatched swab effects that can accelerate in a heartbeat. “When we’re designing fluids, we’re not only concerned with getting there, but getting out of the hole without collapsing the hole on the way out, or having a well control event and going underbalanced by just pulling out of the hole,” he said. 

Elusive sweet spot. Half of the procedures drawn up during the months of pre-planning for an extreme ERD well deal with contingences, so “you’re not waiting until you have an issue to start thinking about it,” Holub said. Moreover, those issues tend to compound, such as when reducing flowrates to control ECD, which, in turn, leads to insufficient hole cleaning or adversely affects telemetry. 

“Somewhere’s that sweet spot, so you can solve all the problems to get you there versus 100% of the answers on one, and zero percent answers on another. The solutions exist, but it takes a lot of specialized experience and people who know how to react to the ECD, and other scenarios you won’t see every day on a normal drilling application,” he said. 

In the meantime, despite the near-routine drilling of wells with staggering lateral lengths, Holub believes the end is not yet in sight. “We’re not even scratching the surface of the capabilities of ERD. We’re often asked, ‘how do you drill these wells, and what do you do if you want to go farther?’ Well, you get a bigger nail and a bigger hammer.”  

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.