Piercing thick flow problems

From mud slurries to butter, tough measurement problems often call for clever solutions.

By Dan Hebert, P.E.

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Difficult flow measurement problems require innovative solutions, ranging from using existing flowmeters in a unique way to developing entirely new technologies because current instruments can’t handle the application. In this article, we’ll look at several creative solutions to flow measurement issues.

Build a better Coriolis meter

Keith Simpson is the I&E controls manager for Continental Carbon, which makes carbon black in Houston. Simpson recently helped develop a new process for producing carbon black, but he and his colleagues couldn’t measure mass flow with any existing products. They had to measure the mass flow rate of a feedstock coming out of a preheater at 500-600 °F.

“At the time, no manufacturer made a Coriolis meter that would run at temperatures that high,” says Simpson. “We tested several, burned them up in our pilot plant, and proved they wouldn’t work.”

Simpson explained the problem to Micro Motion, which developed the DT Series Coriolis meter to address his issue (Figure 1). “The meter ran very successfully, gave us the accuracy we required, and operated at the full temperature range that was necessary, and we were able to begin manufacturing this very specialized product,” says Simpson. “Without Micro Motion, I don’t think we’d have been as successful. We would have had to do things differently, and we wouldn’t have been as efficient.” [A video about this application is available here.]

Extreme environments

“The difficulty of applying flowmeters to most processes tends to increase when the application entails relatively extreme operating conditions,” explains David Spitzer, partner and co-founder at consultant Spitzer & Boyes. For example, a metal flowmeter is usually better than a plastic flowmeter if the fluid is hot. The flow of abrasive fluids is usually better measured using an obstruction-less flowmeter. Flowmeters that can be easily cleaned are usually preferred when fluid can plug the sensing element.

“Applications that exhibit one of these relatively extreme operating conditions generally tend to eliminate consideration of several flowmeter technologies. Further, it can be downright difficult to find a viable flowmeter that can measure accurately when multiple extreme operating conditions are present at the same time.”

In one application, Spitzer had almost the same problem as Simpson—trying to measure hot fluids, this time in an incinerator. The incinerator temperature was controlled to maintain approximately 1,000 °C by measuring and controlling flows of various simultaneously fired fuels, fume streams from various process units and combustion air. 

“The operators wanted a meter to measure the flow of distillation residues to the incinerator, so they’d know the pipe was properly cleaned and not plugged,” says Spitzer. “So the flowmeter had to measure liquids and gases that could be hot or warm, plus be rugged enough for the operator to occasionally use a hammer and chisel to remove solids from its body.”

In this case, the solution was a wedge flowmeter. “The differential pressure that a wedge flowmeter produces can measure liquids and steam,” says Spitzer. “The flowmeter was fitted with chemical tee and remote diaphragm seal connections that eliminated impulse tubing, and located the diaphragm flush with the flow. The operators could unbolt the diaphragm seals and chisel out residue from the rugged all-metal, wedge-flow element. A local switch was installed to signal the type of operation, residue or steam, so the control system would know when to include the heat value of the residue in the incinerator’s heat calculations.”

Clobbered by mud

Unlike the challenges of heat, Jason Norman, a consultant and drilling fluids engineer with Zaxxon Instruments, had a clogging problem with drilling mud, and he solved it with plumbing and maintenance.

“We were working with a large independent operator in the Texas Panhandle, using two 4-in. Coriolis meters on the mud pumps plains. “We incorporated green cement into the active mud system, which caused the drilling fluid to gel up due to excessive water incorporated into the system. We refer to it as ‘clobbered up mud.’ We didn’t have a meter bypass built into the plumbing, which resulted in excessive downtime while we waited for the crew to break apart the meters to clean the inside of the tubes.

“The lessons we learned were to always build in a meter bypass, so operations can continue pumping during meter maintenance intervals, and develop preventive maintenance routines for operations that can cause cold mud to gel inside the meters.”

Denver Smart, vice president of oil and gas marketing at Emerson Process Management, reports that the growing trend to cut drilling costs despite increased well complexity has prompted oilfield service companies to implement more advanced measurement solutions for drilling fluids (mud) management. “Using flowmeter technology to continuously measure drilling fluid returns is a challenging application,” says Smart. “The various oil-water-base slurries, changing physical properties, potential for entrained gas and the presence of rock cuttings significantly impact the accuracy and reliability of flow and density instruments.”

Coriolis flowmeters are widely used in oilfields. Before Coriolis, methods for measuring flow typically involved mechanical paddle meters and/or pit-level measurements. Both have issues with accurate and/or timely flow measurement of the drilling fluids return stream.

“For Coriolis technology, the measurement performance at flow trndown ratios up to 100:1 lets us use large-capacity meters to prevent erosion and cuttings plugging the flow line, while reducing backpressure effects in gravity-feed applications,” Smart explains. “Best practices have been established to ensure full stream flow through the meters under gravity feed, resulting in real-time sustained measurement performance and reliability. This provides a level of drilling operational diagnostics to avoid well-control events, reduced drilling efficiency and higher operating costs.”

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