Flare Monitoring Regulatory Compliance and Analyzers: An Analysis

Flare Monitoring Regulatory Compliance and Analyzers: An Analysis

By Scott Eddleman, Analytical Sales Manager, Yokogawa

In 2016, the EPA finalized its refinery sector rule on maximum achievable control technology (MACT) regulations, and gave refineries 18 months to comply with the requirements for flare monitoring (Figure 1). The rule, 40 CFR 63 Subparts CC and UUU, affects any refinery with a flare used as a control device for an emission point, and those refineries must be in compliance by January 30, 2019.

Figure 1: EPA rules 40 CFR 63 Subparts CC and UUU requires monitoring of flares in refineries.

In this article, we’ll review the requirements and describe the three types of analyzers refineries can use to ensure compliance.


Flare Regulations

The new regulations set flare operating limits, require a flare management plan (FMP), and require a continuous parameter monitoring system (CPMS) plan. The new regulations also cover pilot flame monitoring, visible emissions and flare tip velocity—requirements previously found in earlier versions of the rule.

Parameters that must be monitored in the FMP include:

  • Btu
  • Net heating value in the combustion zone (NHVcz)
  • Net heating value dilution parameter (NHVdil)
  • Vent gas composition

The FMP rule applies to a flare actively receiving perimeter assist air, or to a flare with the potential of operating above its smokeless capacity. A CPMS plan as defined in rule CFR 63.670 is required for each flare, and the owner or operator must have the CPMS plan available on site at all times.

Information required in the CPMS plan includes identification of the specific flare being monitored, flare type, parameters to be monitored, expected parameter range including worst case and normal operation. Also required are descriptions of the monitoring equipment, data collection and reduction systems—along with routine quality control and assurance procedures.

The FMP rule specifically states, “For each flare, the owner or operator shall operate the flare to maintain the net heating value of flare combustion zone gas (NHVcz) at or above 270 British thermal units per standard cubic feet (Btu/scf) determined on a 15-minute block period basis when regulated material is routed to the flare for at least 15 minutes.”

The rule also says, “For each flare actively receiving perimeter assist air, the owner or operator shall operate the flare to maintain the net heating value dilution parameter (NHVdil) at or above 22 British thermal units per square foot (Btu/ft2) determined on a 15-minute block period basis when regulated material is being routed to the flare for at least 15 minutes.”

And most important, the CPMS must “…allow the (EPA) Administrator to confirm that the selected site-specific operating limit(s) adequately ensures that the flare destruction efficiency is 98 percent or greater or that the flare combustion efficiency is 96.5 percent or greater at all times.”

Combustion efficiency, net heating value in the combustion zone, and net heating value dilution parameter are calculated as defined in rule CFR 63.670.

Required data needs to be gathered, calculated, stored and structured for reporting. This can be done with a new or an existing data management system. Data from analyzers used to monitor flares is typically sent to the data management system via some type of digital communications link such as Modbus, Ethernet or fiber optics to handle the large amount of data.

While various parts of the regulations also require monitoring the pilot flame, visible emissions, flare tip velocity, opacity and emissions at the fence line—in this article we’ll concentrate on how to analyze for Btu, NHV and composition.

Analyzers that can be used to meet these parts of the regulations include a Wobbe Index or Btu analyzer, a gas chromatograph and a mass spectrometer.


Wobbe Index Analyzer

Wobbe Index or Btu analyzers (Figure 2) are widely used in refineries to measure Btu and hydrogen in various processes, and to analyze quality of fuel gases. The analyzer is a calorimeter that burns a sample to measure the oxygen content in flare gas and calculate the Wobbe index. The Wobbe index defines the heating value of gas expressed in Btus per standard cubic foot.

Figure 2: Wobbe Index Btu analyzer.

A Wobbe analyzer provides an instantaneous reading of Btu, so it easily meets the requirements for a 15-minute response time. However, because it measures only Btu, it can only indicate that the flare is at, above or below the limits. It doesn’t measure any other components, so it can’t provide any information on why a problem may exist.

Wobbe Index or Btu analyzer installation requires a sample conditioning system, an analyzer shelter, instrument air header, atmospheric vent header with a flame arrestor, power supply, and instrument cabling. All components must be designed for Class 1 Division 1, Group B/C/D, T3 inside and Division 2 outside operation.

Typical installed cost of a Wobbe analyzer is about $215,000.


Gas Chromatograph

Refineries use gas chromatographs (Figure 3) to analyze many different process streams, so they are quite familiar with their operation, a major advantage of this technology. Some of the leading applications include component level concentration measurements, compositional analysis of finished products, or analysis mid process.

Figure 3: A gas chromatograph, such as these Yokogawa GC-8000s, analyzes components in flare gas.

A gas chromatograph (GC) measures components of the flare gas via a flow-through tube, called a column. As the flare gas sample passes through the column, it reacts with a column filling—called a stationary phase—which separates the gas into various compounds. Each compound exits the column at a different time, where it is detected and identified. Measurement data can be calculated to provide Btu, critical for flare gas monitoring.

While a gas chromatograph provides a great deal of information about gas composition, it can be slow to provide this data. In fact, it might not meet the 15-minute response time rule, depending on the number of components and their composition.

So, to meet the requirements for flare monitoring, a GC may need to be tuned to analyze only certain groups of components. For example, a GC might only analyze for methane, hydrogen and carbon dioxide. After analysis, it produces a chromatogram, showing peaks and baseline for each component (Figure 4).

Figure 4: A Yokogawa GC8000 gas chromatograph provides peak and baseline data for multiple components.

GC installation requires a sampling system with pneumatically actuated stream selection valves, an insulated and heated NEMA 4X fiberglass enclosure for the sampling system, a heated and insulated carbon steel enclosure for the GC, and a cylinder rack for carrier and calibration gases. All components must be designed for Class 1 Division 1, Group B/C/D, T3 inside and Division 2 outside operation.

Typical installed cost of a gas chromatograph is about $164,000.


Mass Spectrometer

Refineries typically are not familiar with mass spectrometers, so a plant’s engineers and technicians would have to learn a new technology. A mass spectrometer has an ion source, a mass analyzer and a detector. The ionizer converts the sample into ions, which are sent to the mass analyzer and the detector. The detector calculates the value of each ion to determine the quantity of each ion present, and provides Btu data.

A mass spectrometer is an expensive, complex analyzer, but it offers two advantages: First, a mass spectrometer can analyze 30 components in about 12 seconds, easily meeting the 15-minute response time rule; second, a mass spectrometer can be configured to handle multiple streams.

Since a refinery typically has multiple flares requiring monitoring, a single mass spectrometer could handle multiple flares—depending, of course, on the distance from the flares to the analyzer. A stream switching system could direct samples from each flare to the mass spectrometer on a rotating basis.

Installing a Mass Spec requires a sampling system, an insulated and heated NEMA 4X fiberglass enclosure for the sampling system, and an environmentally controlled steel enclosure for the analyzer. Gas cylinders are mounted remote from the analyzer cabinet with pressure regulators, cylinder chains, and a rack for cylinders. Note that up to 12 gas cylinders may be required. All components must be designed for Class 1 Division 1, Group B/C/D, T3 inside the sample system enclosure and Division 2 outside the sample enclosure.

Typical installed cost of a mass spectrometer is about $245,000 for a single flare. If multiple flares are to be monitored, a more complex sampling system is required, with correspondingly higher costs.

The Comparision Table summarizes the cost and design considerations for each of the three types of measurement.


Measurement Type Comparison Table


Wobbe Index

Gas Chromatograph

Mass Spectrometer

Response time


Varies, can exceed 15 minutes

12 seconds

Components Monitored

Btu, Hydrogen

Up to 10 (limited by response tine)


Approximate Installed Cost




Refinery Familiarity








Operating Cost




Calibration requirements




Maintenance requirements





Combining Technologies

In some applications, best results will require combining technologies, or applying some other creative solution.

For example, possibilities for a two-flare refinery, A Btu analyzer and a GC analyzer can be used in combination. The system had a single sampling system with two sample streams—one from each flare. The Btu analyzer provides rapid analysis of the flare gas streams for reporting compliance, while the common gas chromatograph provides compositional analysis for process trouble shooting.

For a refinery with three flares, a possible solution is to install a single mass spectrometer. It would have common sampling system with three sample streams—one from each flare. The mass spectrometer is capable of switching process streams fast enough to meet monitoring and reporting requirements.



The impending EPA rule, 40 CFR 63 Subparts CC and UUU, is forcing refineries to monitor flares. Fortunately, modern analyzer technology makes it possible to meet the requirements, generate the necessary reports, and stay in compliance.


About the Author

Scott Eddleman has 20 years of analytical experience, including three years with Measurementation as quality/test manager for analytical integration, and 16 years with Yokogawa as a quality control manager, engineering manager and operations manager. His current role with Yokogawa Corporation of America is Analytical Sales Manager for North America.