Estimating Air Emissions from Oil and Gas Operations - revised 28 Nov. 2019
December 29, 2015

(Updated 28 November 2019)

 

Everyday environmental professionals estimate air emissions from oil and gas production facilities and supplying data that is used to make decisions that cost companies money. Typically, the estimation uses a combination of methods as described in this blog. Notably, this data affects the following:  

  • Type and capacity of air pollution controls installed.
  • Air permit type (minor or major source) that applies based on the emission source or facility total emissions.
  • Greenhouse gas (GHG) annual reporting requirements for the mandatory EPA reporting and voluntary industry reporting.
  • Criteria and hazardous air pollutant (HAP) annual reporting requirements to state agencies.

 

 Why is it important to determine emissions as accurately as possible?

  • Overestimating facility air emissions may trigger major source Part 70/Title V air permitting or require mandatory GHG reporting under 40 CFR 98. Also, keeping emissions as low as possible can help a facility qualify for a “general” minor source air permit (e.g., TCEQ PBR). General permits have a much shorter wait time for approval than individual minor source air permits.
  • Underestimating emissions may cause compliance issues. For example, required engine emissions stack test (e.g., NSPS JJJJ for engines) could yield a higher emission rate than used in the air permit or required by an applicable standard. Typically, a site specific source/stack test will be more reliable than a published emission factor.
  • Facilities required to submit annual emission inventories to state regulatory agencies pay emission fees based on actual mass amount of air emissions of criteria pollutants and/or HAP emissions. 

 

Methods Used

Typical methods used to estimate air emissions include:    

  1. Emission factors and equations supplied by a regulatory agency. The U.S. Environmental Protection Agency (EPA) publishes the most widely used document known as AP-42, Compilation of Air Pollutant Emission Factors.
  2. Emission factors and equations required by the EPA for GHG reporting under 40 CFR Subpart 98.
  3. Emission factors generated by a manufacturer or supplier. Most engine and catalytic converter suppliers will have published emission data for their products.
  4. Source/emission testing. This includes stack testing engines and vent gas measurement and chemical analysis. Many operators prefer direct measurement of vent gas from storage tanks.
  5. Process simulation software from trade organizations (API) and facility process design simulators.
  6. Material balance calculations. Use the difference between inlet mass and outlet mass of a product to estimate losses to the atmosphere for H2S, SO2, VOCS and particulate matter (soot).
  7. Stack testing of engines and enclosed combustors (ECD).
  8. Direct measurement of vents by metering gas flowrates and vent gas chemical analysis. The ideal gas law relationships can be used with the direct measurement data to calculate mass of natural gas components vented or combusted.

Emissions data from a source test, process simulator, material balance and metered volumes are usually expressed in units of lbs of pollutant per hour. This data can be converted to a site specific emission factor (EF) by expressing the emissions data as the mass of emissions per unit of activity (e.g., lbs VOCs per barrel of oil throughput for storage tank or lbs of pollutant per MMSCF gas throughput for a glycol dehydrator).

For example, HY-BON/EDI’s IQR services measure the volume of gas vented from a storage tank during a 24-hour period, then sample and chemically analyze the vent gas to yield a lbs of VOC per hour rate. Combining this data with the oil production rate (average barrels per day) allows the user to calculate an emission factor based on the lbs of VOC vented per barrel of oil throughput in the storage tank.

 

Emission Factor Formulas

The general equation for emissions estimation using emission factors is:

E = (A) x (EF) x (1 - ER/100)

where:

E = emissions

A = activity rate (e.g., BOPD, amount of fuel burned per hour, hours operated, volume of gas vented)

EF = emission factor (e.g., lbs VOC per standard cubic feet natural gas vented)

ER = overall emission reduction efficiency (%), if emission controls are operating

 

AP-42 Emission Factor Ratings

AP-42 supplies “Ratings” for emission factors that range from A through E and Unrated, “U”. An “A” rating being “Excellent” considered the most favorable factor. The rating are based on source test data taken from facilities in the industry population. The larger number of samples across a specific source type, the higher the rating.

Due to the large variation in emissions from internal combustion engine and changing emissions standards, AP-42 emission factors may not be the best choice, especially when an engine emission stack test is required.

 

Potential Issues When Calculating Air Emissions

  • Using the wrong emission factor based on the process or emission source type. For example, using emission factors for a 2-cycle, lean burn spark ignition engine for a 4-cycle, lean burn spark ignition engine based upon a lack of enough data for the engine operating.
  • Changes in published EPA and state regulatory emission factors can require a facility to recalculate emissions and comply with applicable standards based on use of the new/updated emission factor.
  • Changes in facility crude oil, condensate and natural gas chemical makeup based on new well production.
  • For process simulations, use of inaccurate data inputs (e.g., operating pressures and temperatures) or use of data not representative (e.g., gas analyses) of the process or products produced.
  • Applying a site specific emission factor to another facility that is not representative of operating parameters, fuel used or chemical makeup of the crude oil, condensate or natural gas produced.
  • Underestimating or overestimating the emissions reduction from an emission control device.

 

Air Pollutants calculated 

  • Criteria pollutants: NOx, CO, VOC, SO2, PM2.5, PM10
  • Hazardous air pollutants (HAP): benzene, toluene, ethylbenzene, xylenes, n-hexane
  • Greenhouse gases (GHG): CO2, methane, N2O

 

 Oil & Gas Emission Sources and Emission Factors

Emission Source Type Typical Sources for Emission Factors and Estimation Methods
Amine gas sweetening units AmineCalc; process simulators; direct measurement
Crude oil, condensate, produced water, volatile organic liquids storage tanks AP-42 Chapter 7 and EPA TANKS4 program; process simulators; pressurized oil sampling with chemical analysis; direct measurement
Crude oil and condensate loading - trucks, barges, ships Ap-42, Chapter 5
Flares and enclosed combustors  AP-42, Chapter 13; state regulatory agencies (e.g., TCEQ)
Fugitive sources from valves, flanges, connections, pump and compressor seals  AP-42, Chapter 5; API Documents 4638, 4589, 4615; 40 CFR 98 Subpart W for GHGs; state agencies
Fugitive dust/particulate matter AP-42, Chapter 13; state regulatory agencies
Glycol dehydrators GRI-GLYCalc; process simulators
Heater treaters, line heaters, reboilers AP-42, Chapter 1
Internal combustion engines - reciprocating, turbines Vendor data; AP-42 Chapter 3; stack testing
Pneumatic pumps, controllers that use natural gas  Vendor data; 40 CFR 98 Subpart W for GHGs
Venting of natural gas from wells and facility processes Metered or calculated volume, gas analysis and ideal gas law equations

 

Resources for Air Emission Estimation

Below is a list of commonly used resources for emission factors and estimation methods for oil and gas industry stationary sources.

Criteria and Hazardous Air Pollutants

  • Oil and gas process simulators such as Aspen HYSYS,   Bryan Research & Engineering, Inc. ProMAX, Virtual Materials Group VGM. These simulator can calculate emissions from glycol dehydration, storage tanks and amine gas sweetening units.
  • AMINECalc Version 1.0 – Amine Unit Emissions Model (API Publication 4679) by American Petroleum Institute
  • USEPA technical air pollution resources includes the CHIEF Clearinghouse for Inventories & Emissions Factors. Under CHIEF can be found emission factors and estimation tools (software) to calculate air emissions.
  • AP-42, Compilation of Air Pollutant Emission Factors: Vol.1: Stationary Point and Area Sources,
  • TANKS software – based on methods in AP-42 Chapter 7: Liquid Storage Tanks. The methods used in TANKS software only calculate standing and working losses – no flashing losses calculated.
  • E&P TANKS (API Publication 4697) by American Petroleum Institute is a software that uses site-specific information to estimate emission from petroleum production storage tanks. Includes standing, working and flash losses. After December 31, 2018, API does not sell new licenses or support this software.
  • GRI-GLYCalc,Ver 4 software – program for estimating air emissions from glycol dehydration units that use triethylene glycol (TEG), diethylene glycol (DEG) or ethylene glycol (EG).

Greenhouse Gases

 


 

Concerned about Venting of Natural Gas?

Let HY-BON/EDI assist your company with your LDAR needs. Using our Identify, Quantify and Rectify (IQR) services and our ongoing Vent Gas Management (VGM) system, we can help you stay in compliance with LDAR requirements. HY-BON/EDI’s vent gas management (VGM) system is a cost effective way to take this issue off of your plate. We use “best in class” vapor recovery units (VRU), Vapor Recovery Towers (VRT) and enclosed combustion devices (ECD or VCU) to comply with storage tank emission control requirements. 

Avoid regulatory compliance issues by remotely monitoring the state of tank hatches, gates, valves, and other mechanisms. HY-BON/EDI’s. Hatch Sense is the only safe, wireless thief hatch alert system with monitoring capabilities. Since we meet the UL Class 1 Div 1 requirements for intrinsically safe equipment Hatch Sense can be deployed now at your production facilities and solve problems. Operators can use Hatch Sense to demonstrate to regulators their proactive approach to minimizing leaks and increasing compliance.

 


Cimarron Energy Acquisition of HY-BON/EDI

Cimarron’s acquisition of HY-BON/EDI in July 2019 means that our environmental product and services offered to our oil and gas customers are further strengthened. This includes the following:

  • BTEX combustor unit for glycol dehydrators
  • Mobile glycol reclamation system
  • Vapor Recovery Units (VRU)
  • Vapor Recovery Towers (VRT)
  • Flares
  • Enclosed Combustion Devices (ECD)
  • Leak Detection and Repair (LDAR) services
  • Vent gas measurement services
  • Field service
  • Parts

For more information on our products and services, you can contact us at +1 (844) 746-1676 or visit https://www.cimarron.com.