Measuring and Verifying Emission Performance — From OGI to Direct Measurement

1. Start by defining the measurement question

• Do we need to locate an unexpected release?
• Do we need to compare the relative performance of several tanks?
• Do we need a regulatory compliance measurement?
• Do we need to validate an emission-factor assumption?
• Do we need to prove that a modification reduced emissions?
• Do we need a continuous alarm rather than a one-off test?

These questions require different levels of accuracy, spatial resolution, duration and documentation.

2. Physical inspection remains fundamental

Many emission failures are visible without sophisticated instrumentation: a damaged secondary seal, an open gauge hatch, a poorly fitting deck cover, missing gasket, blocked vent or displaced seal fabric. A structured tank walk and roof inspection often provides the fastest explanation for a model discrepancy.

Inspection also creates the context needed to interpret instrumental results. Seeing a plume at a fitting is more useful when the fitting type, position and mechanical condition are known.

3. Optical gas imaging

OGI uses infrared imaging to make certain hydrocarbon gas releases visible. It is highly useful for locating and communicating otherwise invisible releases over large equipment areas. EPA’s Appendix K requirements illustrate an important principle: OGI performance depends on camera capability, operator competence and field conditions such as viewing distance, wind and thermal contrast.

OGI should therefore not be interpreted as a universal quantitative meter. A visible plume shows a release under the conditions of the survey; absence of a visible plume does not prove zero emission.

4. Concentration measurements

Portable VOC instruments, fixed sensors and sampling can establish the presence and concentration of hydrocarbons at selected points. They can be valuable around vents, enclosed spaces or the perimeter of a tank, but concentration is not the same as mass emission rate. Air movement and dilution can change concentration without changing source strength.

Use concentration monitoring when the decision is actually concentration-based, or combine it with flow or dispersion information where emission rate is required.

5. Direct and indirect emission-rate measurement

Quantifying tank emissions can involve controlled flow measurement, tracer methods, remote sensing or other site-specific techniques. These methods can be powerful for validating inventory assumptions but require a clear test boundary, representative operating condition and competent data interpretation.

A measurement campaign should record product, level, throughput, temperature, wind and tank operating state so that the result can be compared with the model on a like-for-like basis.

6. Before-and-after verification

Emission-reduction projects should define the verification method before construction begins. Otherwise the project may finish with no defensible way to demonstrate its benefit.

The simplest verification may be an updated AP-42/API MPMS calculation using as-built factors plus inspection evidence that the equipment was installed correctly. Higher-value or uncertain projects may justify OGI, targeted measurements or a formal performance test.

7. Measurement uncertainty is information

Field measurements are affected by instrument accuracy, environmental conditions, spatial coverage and temporal variability. Rather than hiding this uncertainty, use it to decide whether the result is strong enough for the decision. A rough screening survey may be entirely adequate for prioritisation but not for contractual acceptance.

The same principle applies to calculations. The objective is not to eliminate uncertainty but to understand and manage it.

8. Build a verification ladder