Meter Sizing
One of the most difficult parts of the project is identifying what will potentially relieve into the flare header where the transducers/meter will be installed. Typically, this can range from small PSVs to complete process upset and/or fires. Based on the process conditions, GE Sensing will request a range of molecular weights expected, as well as pressures and temperatures, so the meter can "correct" for these variables. Original design information for the plant can be useful.
Meter & Transducer Location
In order to find a section with maximum straight run, it is important to actually walk your flare header rather than merely relying on drawings. Check the installation information for distances from upstream and downstream obstructions. Also, measure the flare header; do not rely on the diameter shown on P&IDs since the meter is specifically fabricated for the exact diameter of your line. The line thickness will also need to be verified. (An ultrasonic thickness reading will be well worth the time and effort.)
Note that 20 diameters are required upstream from an obstruction or change in direction and 10 pipe diameters downstream. Also, 10 feet (three meters) of cable is provided to connect from the transducers junction box to the pre-amp. This is fixed, so take that into consideration as well.
Since a flare will typically have pilot/purge gas controls, you may want to install the flowmeter in this area. And, although the thermowell and tap for the pressure transmitter needs to be on top of the header (downstream of the transducers) consider piping the pressure and temperature readouts down to grade for ease of viewing and comparing to what the flowmeter indicates.
Installing Flow Transducers
Consider yourself fortunate if a shutdown can be scheduled to install the transducers and fittings for the pressure and temperature transmitters. Most process plants do not have this luxury for a variety of reason and instead the installation will be done on a "live line," commonly referred to as "hot tapping."
Hot-Tap Planning & Emergency Response
The exact location of the transducers is critical. GE Sensing provides a Nozzle Installation Kit to assist in locating the nozzles for small and large diameter flare headers. Expect the nozzles to be three-inch/150# fittings, unless otherwise specified. Many companies have specific hot-tap procedures highlighting areas of concern, including:
• Burn-though of the line while installing the nozzles and possible fire.
• Malfunction of the machine preventing it from being removed and/or loss of hot-tap coupon.
• Communication plan between hot-tap company and control room.
• Plan for inerting the line while performing the hot tap; consider introducing an inert gas such as nitrogen to sweep the area.
• A plan for spill containment (do not expect a liquid spill, but recognize there could be liquid present).
• Personal Protection Equipment (PPE) and firefighting response.
As state, national, and international government regulations for monitoring flare gas emissions become stricter, so do the demands for measuring and recording them. Environmental authorities around the world are requiring process plant operators to continuously monitor and record flare emissions and associated flowrates and gas composition. As a result of these new regulations, the industry has adapted by developing various methods to reduce emissions, which in turn has brought the need for higher accuracy measurement at lower flowrates.
Many petrochemical and refinery plants are choosing to install flare flow monitoring equipment rather than calculate the flare flow. A major consideration is the turndown capability (lowest to highest measurement range) of a flowmeter since a typical process plant may have small pressure-relief valves (PSV/PRVs) that relieve from 100 to 1,000 SCFM, but in a major upset or fire, this flowrate could be orders of magnitude greater.
Increasing Government Regulation
A process plant’s flare gas system is typically considered the "sewer" of the plant in terms of waste gas processing. The purpose of a flare gas system is to burn waste gases from the process plant, converting chemical and organic hydrocarbons into primarily water vapor and CO2. Flares allow overpressure situations within vessels to relieve with excess gas being released to the flare for safe combustion.
To control the amount of emissions into the atmosphere, governments around the world are developing new rules and regulations to protect the environment. Within the United States, the Environment Protection Agency (EPA, www.epa.gov) has enforced emission levels of NOx (Nitrous Oxides) and highly reactive volatile organic compounds (HRVOC) through individual states with allocations and fines. In Texas, California, and New Jersey the ozone depletion has led to stricter total emissions and monitoring of HRVOCs.
In Texas, the Texas Commission of Environmental Quality (TCEQ, www.tceq.state.tx.us) Chapter 115 Regulation has set the levels for each flare stack. The new regulations require a flare gas flowmeter to be specified to have +/- 5 percent inaccuracy at 30, 60, and 90 percent of range under its installed condition. End-users would like the meter to be as accurate as possible to as low as possible a flowrate, since each stack is allocated a maximum amount of emissions. Even at low flow, operating continuously can add up to a significant amount of gas, perhaps surpassing the emissions from normal flare gas relief events.
In California an updated Rule 1118 has set new state requirements for flare stack emissions. The updated regulations are essentially the same as Texas with a +/- 5 percent inaccuracy requirement for flow of one foot per second (.3 m/s) and higher, along with a 20 percent inaccuracy for the 0.1 to one f/s (.03 to .3 m/s) flow velocity range.
The European Union (EU, www.europa.eu) has followed suit. In the EU, the guidelines for the monitoring and reporting of greenhouse gas emissions pursuant to Directive 2003/87/EC of the European Parliament and of the Council initially required the measurement uncertainty for flare gas flow to be in the area of 2.5 percent. However, this proved to be impossible to achieve over the complete range of flows observed in flares. The most recent commission decision requires uncertainty in measurement of the flare gas ranging from +/- 17.5 percent in Tier 1, +/- 12.5 percent in Tier 2, and +/- 7.5 percent in Tier 3.
The measurement across the range of flows should be within this accuracy. The uncertainty requirements for the determination of emissions from flares have been lowered in order to reflect the specific technical conditions of these facilities.
A Challenging Application
Flare gas flow measurement is a challenging application, and with emerging regulations it has become even more challenging. Historically, flowmeter technologies, including differential-pressure, vortex-shedding, and insertion thermal mass meters, have been somewhat limited in these applications because of their limited turndown, inability to follow unsteady flows, corrosion, intolerance of liquid carryover, and sensitivity to changes in gas composition. Ultrasonic technology was developed for flare gas measurement back in the early 1980s by Panametrics (now GE Sensing, www.gesensing.com) in collaboration with Exxon in Baytown, TX. Today ultrasonic flowmeters are the industry standard for flare gas measurement with more than 3,500 installations worldwide.
One of the largest advantages of ultrasonic technology is its large turndown ratio. New regulations require monitoring the total emissions of the flare stack from the lowest flow conditions at 0.03 m/s up to 80 m/s during emergency flaring. Ultrasonic flowmeters also perform well despite extreme fluctuations in temperature and pressure. Temperatures range from -20 C to 80 C (-4 F to 176 F) for typical flare systems and from -150 C to 100 C (-238 F to 212 F) for liquefied natural gas (LNG) flares. Pressure ranges from five to 15 kPag (15.4 to 16.9 PSIA) in normal operation to seven bara (101.5 PSIA) under emergency conditions.
Once installed, flare header flowmeters have several functions useful for diagnosing process problems. For environmental reporting and mass balancing, the average molecular weight and mass flowrate derived from the flowmeter signals are typically recorded by the plant’s control system. If a flowmeter indicates gas flow in the flare header when such a condition is not expected under the plant’s operating condition, the installation point of the flowmeter and the molecular weight can both help in tracking down the responsible unit.
Transit-Time at a Glance
Flare gas is customarily wet hydrocarbon gas with dynamically varying pressure, composition, and temperature. The transit-time concept for making measurements, in its most simplistic form, is driven by transducers that transmit an ultrasonic signal from an upstream transducer to a downstream transducer and vice versa (Figure 1). The time difference for the travel times of these transmissions is directly proportional to the flow velocity.
Using the measured velocity and other information (programmed into the meter), other measurements can be calculated, including: volumetric flowrate, speed of sound in the gas, molecular weight, and, more importantly, mass flowrate. The meter can display and output mass flowrate, as well as other measurements, enabling refineries to come into compliance with the environmental permitting requirement. However, mass flowrate can also help customers identify the nature and source of the gas being flared.
Ultrasonic meters have no internal parts that can drift and cause inherent errors. No daily calibration is required, unlike other environmental compliance monitors.
Location & Installation
Finding the right location for a flowmeter is important. Ultrasonic flowmeters, like many other flow measurement technologies, do not measure velocity across the full cross-section of the pipe. As a result, for accurate results they depend on a fully developed flow profile of known shape. For flare headers, the standard advice is to allow a straight length equivalent to 20 pipe diameters upstream of the flowmeter and 10 diameters downstream. This may be difficult to achieve in a flare header with many joints and bends, but it is important for accurate results. (For more on installing and commissioning a transit-time ultrasonic flare flowmeter, see the "Lessons Learned" sidebar following this article.)
James Matson spent the last 27 years in the design, manufacture, application, sales, and promotion of ultrasonic flowmeters. His experience encompasses flow technology for liquids and gases, and for wetted and clamp-on versions of both portable and permanent installation flowmeters. He has been a member of various industry organizations and standards committees including IEEE, ISA, AGA, and IDEA, presenting papers at various forums such as ISA, ISHM, and AGA. He presently manages the global marketing effort for flowmeters and acoustic products for GE Sensing in Billerica, MA. He provides technical support, customer communication, and market analysis to the GE Sensing global field sales and service force, as well as technical and market direction for product development and research.
Rachele Grasso Smith is president of RGS Group, LLC, a women-owned
environmental consulting firm. Mrs. Smith recently commissioned a GF868 ultrasonic flare flowmeter at a major N.J. refinery. Mrs. Smith can be reached at [email protected].
www.gesensing.com
References
1. Industrial Flares, Section 13.5. Sept. 1991, www.epa.gov/ttn/chief/ap42/ch13/final/c13s05.pdf.
2. Flare Gas Ultrasonic Flow Meter, Smalling, Lynnworth, Wallace, Proceedings from the Thirty-Ninth Annual Symposium on Instrumentation for the Process Industries, 1984.
3. Flare Gas Ultrasonic Flowmeters – Optimizing Performance & Verification of New and Existing Installations, Steve Milford, June 2002, NEL Flare Gas Seminar.
