Drilling advances

Like many of its aging brethren, Norway’s nearly 34-year-old Valhall field refuses to allow access to remaining reserves without a fight. Managing to drill through the over-pressured shale overburden that overlays the depleted, compacted chalk production zones is but round one; the knockout blow comes with the repercussions of a limp cement job, which typically metastasizes into sustained annulus casing pressures and costly remediation throughout the well’s life.

One possible solution, says Steve Rosenberg, Weatherford’s global drilling reliability manager, is combining field-proven liner drilling with remotely operated cementing technology to provide selective isolation of troublesome zones. The rotatable system, which exploits the latest in radio-frequency identification (RDIF), is under development with a fourth-quarter 2016 target for field implementation, said Rosenberg during the November IADC Drilling Engineering Committee (DEC) Technology Forum in Houston.

Extreme drilling. In keeping with the forum’s “Extreme Drilling” theme, Rosenberg’s sneak preview of the emerging remote cementing with liner drilling technology was one of two presentations dealing with the travails of North Sea drilling. In another, Bill Burch, executive V.P. of operations and engineering for Mercury Well Control, hit on the unique logistical challenges of a shallow-water, high-pressure, high-temperature (HPHT) development well in the UK sector.

The BP-operated Valhall field, which began production in 1982 from the Tor and Lower Hod reservoirs, features an immediate pore pressure drop of nearly 7 lb/gal across the interface of the pressured shale and the depleted chalk interval, generating severe losses that invariably stick conventional drilling assemblies. Swapping out with a liner or casing drilling system roughly 33 ft above the depleted Tor formation effectively isolated the troublesome zone, reducing losses and allowing the drillable casing bit to reach target, he said.

“That’s fine, but how do you cement it, using conventional cementing techniques?” he asked. “If you cement through the bit, you will lose circulation and not get the necessary wellbore isolation. If you add annular casing packers to the assembly, hopefully you can get mechanical isolation and maybe get some of the cement where you want it. What we see, however, is sustained, annular casing pressure over the life of the well, resulting in millions of dollars being spent on remedial costs.”

With operator collaboration, the drilling and cementing system under development will comprise a series of RFID-tagged port collars on the 95/8-in. drilling liner, an expandable annular casing packer and a hydraulic casing swivel, to allow the liner to be rotated above the stuck pipe interval. Ostensibly, this configuration will allow the cementing port collars to be remotely activated and provide the zonal isolation, and allow cementing operators to begin directly upon reaching target depth, Rosenberg said.

Rig headaches. Across the maritime boundary, a re-started, HPHT shallow-water development program, in the general vicinity of the UK Central Graben area, posed unique headaches not normally associated with the North Sea. “It’s easy to look at the Gulf of Mexico and the Gulf Coast region, and say these are some of the highest-pressured and highest-temperature wells in the world, but in reality the North Sea has some, as well, and they actually can be quite difficult,” said Burch.

In the case that he presented to the DEC forum, the last appraisal well in the field was drilled and tested in 1994, revealing a wealth of offset data, including the pressure and temperature regime, the specifics of which were not released. However, Burch said that in the current drilling program, the intrinsic geological challenges were overshadowed partially by an unlikely problem, given today’s environment: sourcing an appropriate rig.

“We’re in 600 ft of water, which is too deep for a jackup, so we needed a sixth-generation semi, but not a DP (dynamically positioned), as we need something that is anchored to hold position in shallow water,” he said. “There are no anchored fifth- or sixth-generation semis out there. Third- and fourth-generation are all that’s left, as the first two (generations) have officially been scrapped.”

The operator had to settle for a then-cold-stacked older-generation semi with “limited storage capacity, limited deck space and limited lifting capacity,” said Burch.

Owing to the rig limitations, logistical juggling occupied no small part of the drilling operation, including the transition from one fluid stream to another. “We only had 2,600 bbl of pit volume, whereas most new-generation deepwater rigs have 10,000-bbl capacities. We had to get very creative with displacements,” he said, especially considering that the well was to be completed with expensive cesium format brine, making it imperative to avoid any fluid cross-contamination.

Burch said the limited lifting capacity posed tremendous difficulties. “Every time we picked up a crane, we could see pit volume changes. The pitch and roll, relative to heave, can cause 5-to-10-bbl gains, so I’m trying to watch well control while also managing other operations.”

Compounding the rig shortcomings were the notorious North Sea climatic conditions, which posed a host of hazards, especially when trying to lift the tubing head spool and subsea tree from the supply boat to the rig. “This is the North Sea, where dead calm doesn’t exist. In reality, a 65-to-75-ton lift means the supply boat has to be underneath the hull of the rig.

“There is no North Sea captain going to agree to put a boat underneath the rig,” he said, noting that the subsea tree eventually was landed in a two-step deployment from another vessel.  

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.