Drilling advances

Complex and uber-risky exploration and deepwater wells clearly illuminate the frailties of surface measurements and conventional models, further amplifying the compelling need for high-speed, real-time downhole data, said the pseudo-competitive developers of new and re-born telemetry technologies, in separate presentations to the IADC Drilling Engineering Committee (DEC) quarterly forum on Sept. 19.

In non-circulating operations especially, an infinitesimal correlation exists between interpretations based on rig site measurements and what is actually happening downhole, said Andy Hawthorn, director of solutions for XACT Downhole Telemetry. He was describing the company's recently introduced acoustic telemetry system, engineered to enable deepwater operators to manage pressure in real time from drilling through completion. XACT is majority-owned by Shell Technology Ventures and BP Ventures.

“In the current environment, the availability of real-time downhole data on deepwater exploration wells is about 15% of total rig time, and that is on-bottom and drilling ahead. Tripping, casing, cementing, completions, frac packing and the other 85% (of operations) are done blind or inferring from surface measurements and models,” he said.

Tony Pink, NOV senior V.P. of strategic sales, automation and optimization, echoed Hawthorn, saying “we have seen a lot of challenges and a lot of differences between models and real time.” He made the comments while discussing NOV's 10-year-old wired drill pipe technology, recently re-designed to address the cost and reliability issues that prevented wholesale adoption of the original iteration.

No mud required. Unlike conventional mud-pulsed telemetry, where functionality requires a full fluid column and flow, Hawthorn said the XACT acoustic system operates independent of fluid, flow or formation by sending data signals directly through the walls of any drill pipe or workstring to a surface receiver.

Closely resembling drill collars, the measurement and telemetry nodes screw directly onto the workstring and are spaced conservatively throughout a vertical or horizontal wellbore, where they instantaneously send signals from tool to tool. With no moving parts, the bottom of the tool comprises the electronics and acoustic engine, while the middle section houses the sensors, which as of now, detect internal and external temperatures, pressures, weight, torque and bending. The full-bore tools enable the deployment of wireline, cement and 4.5 million lb of proppant.

The acoustic telemetry system has been employed in the deepwater Gulf of Mexico and the North Sea in applications “where people had no access whatsoever to real-time data,” Hawthorn said. For instance, he said deepwater frac packing had been fraught with high rates of reactionary non-productive time (NPT), when surface measurements exhibited pressure spikes, which real-time downhole data revealed were simply the result of proppant inertia.

In a deepwater injection well for an acid wash and perforation, Hawthorn said rather than maintaining a full fluid column and potentially damaging the formation through excessive overbalance, the acoustic telemetry system enabled the operator, with regulatory blessing, to minimize the hydrostatic head by dropping the fluid level 4,000 ft in an 8,000-ft riser. “This is managed pressure completions without managed pressure rig equipment,” he said. “It's old school, but since you know the pressures in the well, you know the mud weight in, and the volumetrics of your riser, you can tell exactly where the top of your fluid is. It's very, very simple, but only if you have real-time data.”

“Lights on.” Meanwhile, Pink said acceptance of the first version of NOV's wired drill pipe telemetry system was hampered by costs that were 2.2 times those of conventional pipe, as well as reliability issues and the industry downturn of recent years. “The cost of ownership is now down to 1.2 times the costs of normal pipe, though with the value it delivers, the model works at 2.2 times the cost of the normal pipe,” he said.

He said the telemetry system, which comprises wires delivering data at a rate of 57,000 bytes/sec and placed snuggly against the pipe wall, was re-designed to improve reliability. “Our uptime (live data) is 95% on U.S. land and 98% to 99% offshore. The resolution we get is also significantly improved. For geosteering, we now turn the lights on downhole, so you can see high-resolution image logs in real time while drilling,” he said.

While the quarterly DEC forum was devoted to “Contemporary Challenges in Exploration Drilling,” Pink said in the speed-absorbed unconventional sector, the telemetry package over six wells sequentially helped reduce drilling time from spud to TD 40% by “taking the data and driving the rig's control system to actually deliver speed.”

For a North Sea operator relying on logging-while-drilling (LWD) signals, the along-the-string measurements relayed by wired drill pipe revealed an “overly conservative” model. “With the along-string measurements, the operator could see, in fact, that the pressures at planned TD gave them significantly extra ECD (equivalent circulating densities) to play with.” So, when they got to TD, they were able to drill an extra 200 m more, and 300 m and 500 m more on the next two wells,” he said.

In a recent exploration campaign in the Barents Sea, Pink said the operator would not have considered seismic-while-drilling, if mud-pulsed telemetry was the only option. “The time involved would have made it impossible. Wired drill pipe enabled them to use seismic-while-drilling to identify shallow gas in the Barents Sea. Because of high-speed telemetry, we could get that data in real time,” he said.