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A differential pressure (DP) sensor, encased in a 1-in. cell, could detect, in real-time, the slightest fluctuation in downhole mud weight that could foretell a kick in extreme high-pressure, high-temperature (HPHT) applications.

While still conceptual, the idea capitalizes on lessons learned from two successful flow measurement initiatives administered through the public/private Research Partnership to Secure Energy for America (RPSEA), funded partially by DOE's National Energy Technology Laboratory (NETL). Those joint industry projects, however, were oriented more on revenue distribution from deepwater wells.

“We believe this downhole mud density sensor can provide additional drilling safety at high temperatures and pressures,” says Jim Hall, director of the Letton Hall Group, which served as principal investigator of the back-to-back RPSEA projects.

Project evolution. The proposed HPHT mud density sensor arose from a 2011 RPSEA project, aimed at engineering a combined pressure-differential pressure (P-DP) sensor. This sensor could be connected at the wellhead to accurately measure multi-phase flow in deepwater production wells. With no sensors then available to measure flow from extreme HPHT zones, the original project was initiated with the primary aim of accurately determining revenue and royalty allocation. “What was missing was flow measurement in deepwater wells, especially with comingled production. Everybody wants to make sure they’re getting their fair share,” he told the final 2016 quarterly Technology Forum of the IADC Drilling Engineering Committee (DEC).

The sensor builds off transducers developed to measure tire pressures on the U.S. Space Shuttle, which had to withstand up to 500°F. After achieving what he described as “unbelievable performance” on the seabed, the technology went in another direction, namely a subsequent RPSEA initiative to put the sensor package downhole. Prior to the follow-up RPSEA project, DP sensors were not only too large for downhole, but they were limited to measuring production fluids at a maximum temperature of 257°F (125°C) and operating pressures no higher than 10,000 psi.

“Operators told us they would not only be drilling in deep water, but also drilling deeper wells, where they would be hitting temperatures and pressures that current flowmeters could not handle,” he said. “The motivation, when we first started, was to be able to measure flow under these conditions at various points in the wellbore. If you’re producing from more than one zone, you’d like to be able to see what’s flowing from a particular zone.”

Taking the technology to hot, pressured deepwater horizons presented some challenges, not the least of which was shrinking the sensor cell enclosure from the 2-in. version to 1 in. or less. The sensor, likewise, has to withstand production fluids under HPHT conditions of at least 482°F (250°C) and 15,000 psi, and have a maximum uncertainty of less than 0.1% full scale, taking into account linearity, repeatability and hysteresis.

According to a final report last September, the condensed prototype HPHT sensor cells were calibrated at ambient pressure and temperature conditions to verify that performance objectives had been met. “At ambient, the performance was better than even we expected,” Hall said, pointing to a realized total uncertainty of .006% of full scale, after testing at the prescribed 250°C, to determine the effect of extreme temperature. “Everything was linear, and the important part was that we had equal spacing for equal temperature changes, which means you can compensate for temperature very simply. You don’t need a complicated polynomial equation to compensate for temperature.”

Kick detection. Hall singled out former RPSEA President James Pappas and NETL Technology Manager Roy Long as pushing the concept of using the newly developed sensor cell to measure active mud density changes to provide early kick detection. “Because of the good performance we were seeing, they suggested we look at the possibility of using this to accurately measure the density of the mud, or whatever else may be in the wellbore, to get an early indication of a kick,” he told the DEC forum, which coincidentally was held the morning after the U.S. presidential election on Nov. 8. “We’ve always had great support from the people at the DOE, and hopefully that will increase.”

Along with routine surface mud density measurements, attempts at measuring fluctuating fluid properties while drilling typically take the form of electric conductivity, ultrasonics or bulk density measurements with gamma rays, which require a radioactive source. Combining the sensor cell with wired drillstring technology conceivably could provide more accurate and real-time kick detection, but Hall said a number of issues would have to be resolved first.

“What does it (data) mean in terms of what is the minimum, measureable lb/gal change in density? Can we really see enough of a change to determine if something is happening; if inflow into the wellbore is changing the mud density?”

Moreover, the downhole DP sensor delivers a pressure differential of roughly 75 psi, which would have to be reduced exponentially to detect scant mud density changes. “Instead of a 75-psi differential measurement, we’re talking below 1 psi. That’s not too easy, but if we design a DP (sensor) chip for a very low range, we think we can do it,” he said.

“Right now, we’re putting together tubes for static calibration, so this is not yet a completed project,” Hall said. “The sensor performance has been excellent. However, it won’t do any good unless someone adopts this technology and puts it in their system.” 

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.