1. Overview
Fugitive emissions are unintentional releases of gases or vapors from process equipment during normal operations. Unlike stack emissions from combustion sources, fugitive emissions originate from equipment leaks at valves, flanges, pump seals, compressor seals, connectors, and other components. In the oil and gas industry, fugitive methane emissions are both an environmental concern (potent greenhouse gas) and an economic loss (lost product).
Gathering & Boosting
Compressor Stations
Compressor seals, piping connections, pneumatic devices, and tank vents are primary sources.
Gas Processing
Treatment Facilities
Amine units, dehydration systems, fractionation equipment with thousands of components.
Transmission
Pipeline & Metering
Meter stations, block valve sites, pig launchers/receivers with intermittent venting.
Production
Wellsite Equipment
Separator vents, pneumatic controllers, tank flash gas, and casing vent emissions.
Superemitters: Studies consistently show that a small fraction of components (often less than 5%) are responsible for the majority of total emissions (often more than 50%). Effective LDAR programs focus on finding and fixing these high-emitting components quickly, rather than simply surveying as many components as possible.
2. Emission Source Types
Component-Level Sources
| Component Type | Typical Count (per facility) | Average Leak Rate | Primary Leak Point |
|---|---|---|---|
| Valves | 100-1,000+ | 0.1-10 scfh | Stem packing, body-bonnet joint |
| Flanges/connectors | 200-2,000+ | 0.01-1 scfh | Gasket face, bolt tension loss |
| Pump seals | 5-50 | 1-50 scfh | Mechanical seal faces |
| Compressor seals | 2-20 | 5-200 scfh | Rod packing, shaft seals |
| Pressure relief devices | 10-100 | 0.1-100 scfh | Seat leakage, simmer/blowby |
| Open-ended lines | 10-100 | 0.5-20 scfh | Sample connections, drain valves |
Equipment-Level Sources
Non-Component Fugitive Sources:
Pneumatic devices:
High-bleed controllers: 6-20 scfh (continuous)
Low-bleed controllers: < 6 scfh (continuous)
Intermittent-bleed: Varies with actuation frequency
Tank emissions:
Flash gas from liquid dumps
Working/breathing losses
Thief hatch leaks
Dehydration systems:
Glycol still vent (BTEX + VOC)
Flash tank gas
Compressor blowdowns:
Unit blowdowns during starts/stops
Rod packing vent gas
3. EPA Method 21
EPA Method 21 is the reference method for detecting and quantifying VOC leaks from process equipment. A portable organic vapor analyzer (OVA) or flame ionization detector (FID) is used to screen individual components for leaks.
Method 21 Procedure:
1. Calibrate instrument with reference gas (methane)
2. Position probe at potential leak interface
3. Move probe slowly around component perimeter
4. Record maximum concentration reading (ppm)
5. Compare to applicable leak definition threshold
Leak Definitions (ppm, as methane):
NSPS OOOOa (most components): 500 ppm
Connectors: 500 ppm
Pumps in light liquid service: 2,000 ppm (monthly)
or 10,000 ppm (quarterly)
Valves in gas/vapor service: 500 ppm
Instrument Requirements:
Detection principle: FID, PID, or catalytic oxidation
Range: 0-10,000 ppm (minimum)
Response time: ≤ 30 seconds
Calibration: Daily with reference gas
Screening Value Interpretation
| Screening Value (ppm) | Classification | Typical Action |
|---|---|---|
| < 500 | No leak detected | Record as "no leak," continue monitoring |
| 500-10,000 | Leak detected | Tag for repair, first attempt within 5 days |
| 10,000-50,000 | Significant leak | Priority repair, potential health/safety concern |
| > 50,000 | Major leak | Immediate action, safety assessment required |
4. Optical Gas Imaging (OGI)
Optical gas imaging uses infrared cameras tuned to hydrocarbon absorption wavelengths to visualize gas plumes that are invisible to the naked eye. OGI can survey large numbers of components quickly and is accepted as an alternative to Method 21 under NSPS OOOOa.
OGI Camera Technology:
Cooled detector: InSb (indium antimonide)
Spectral range: 3.2-3.4 μm (C-H stretch absorption)
Sensitivity: ~0.3-1 g/hr methane (wind-dependent)
Survey rate: 500-2,000 components per hour
OGI vs Method 21 Comparison:
Method 21: Quantitative (ppm), slow (30-50/hr), contact
OGI: Qualitative (visual), fast (500-2,000/hr), remote
NSPS OOOOa OGI Requirements:
Survey frequency: Semiannual or quarterly
Operator: Trained per manufacturer guidance
Wind speed: Record during survey
Must be able to detect 60 g/hr reference leak
Monitoring plan must be documented
Alternative Detection Technologies
| Technology | Coverage | Sensitivity | Status |
|---|---|---|---|
| Continuous monitors (fixed) | Facility-level | ~1-10 kg/hr | Emerging, some regulatory acceptance |
| Drone-mounted sensors | Component or facility | ~1-5 g/hr | Emerging, pilot programs |
| Satellite-based detection | Basin-level | ~100-1,000 kg/hr | Operational for large emitters |
| Acoustic leak detection | Component-level | Qualitative | Supplemental use only |
5. Regulatory Requirements
NSPS OOOOa (2016) Key Requirements
Affected Sources (New/Modified/Reconstructed):
Well sites, centralized production facilities,
compressor stations, pneumatic controllers,
pneumatic pumps, storage vessels
LDAR Requirements:
Frequency: Semiannual (OGI) or annual (Method 21)
Leak definition: 500 ppm (Method 21) or visible (OGI)
Repair timeline:
First attempt: within 30 days of detection
Final repair: within 30 days of first attempt
Delay of repair: documented justification required
Pneumatic Controller Requirements:
New controllers: Zero-emission or route to VRU
Existing: Not affected by OOOOa (grandfather)
NSPS OOOOb (2024) Updates
Key Changes from OOOOa to OOOOb:
1. Covers EXISTING sources (not just new/modified)
2. Quarterly monitoring required at most facilities
3. Super-emitter response program
4. Applies to production, processing, and transmission
5. More stringent pneumatic device requirements
6. Expanded well site monitoring requirements
State Implementation:
States submit implementation plans
Minimum federal standards as floor
States may adopt more stringent requirements
Reporting and Recordkeeping
| Requirement | Frequency | Content |
|---|---|---|
| Annual report | Yearly | Leak counts, repair records, component counts |
| Survey records | Each survey | Date, operator, weather, results by component |
| Repair records | Each repair | Date found, date repaired, method, re-monitoring |
| Emissions inventory | Yearly | Total VOC and methane emissions by source |
6. Emission Quantification
Estimation Methods
Emission Factor Method (Simplest):
E = EF × N × t
Where:
E = Total emissions (lb/yr or ton/yr)
EF = Emission factor (lb/hr per component)
N = Number of components
t = Operating hours per year
EPA emission factors are published in:
- AP-42, Chapter 5.2 (petroleum industry)
- EPA Protocol for Equipment Leak Estimates
- 40 CFR 98 Subpart W (GHG reporting)
Correlation Equation Method (More Accurate):
Uses Method 21 screening values with EPA correlation
equations to estimate mass emission rates:
E_component = f(screening value in ppm)
This method gives component-specific rates rather
than population averages.
Direct Measurement (Most Accurate):
High Volume Sampler (Hi-Flow):
Captures full leak and measures mass flow
Range: 0.01 - 12 scfm
Used for individual component quantification
Emission Factors by Component
| Component | Service | Factor (kg VOC/hr) |
|---|---|---|
| Valve | Gas | 0.0268 |
| Valve | Light liquid | 0.0109 |
| Pump seal | Light liquid | 0.0199 |
| Connector | All | 0.00183 |
| Flange | All | 0.00183 |
| Open-ended line | All | 0.0023 |
7. LDAR Program Design
Program Elements
- Component identification and tagging (initial inventory)
- Monitoring schedule and method selection (OGI, Method 21, or combination)
- Leak definition and action thresholds
- Repair procedures and timeline requirements
- Delay of repair documentation process
- Quality assurance and quality control procedures
- Recordkeeping and reporting systems
- Training requirements for monitoring personnel
Cost-Effective LDAR Strategies
Tiered Monitoring Approach:
Tier 1: Continuous monitoring (facility-level)
Fixed sensors detect large leaks immediately
Triggers targeted survey of indicated area
Tier 2: Periodic OGI survey (quarterly/semiannual)
Screens all components quickly
Identifies visible leaks for repair
Tier 3: Method 21 follow-up (as needed)
Quantitative measurement of detected leaks
Repair verification and re-monitoring
Economic Value of Leak Repair:
Natural gas value: ~$3/Mcf (varies)
Average leak: 2 scfh = 48 scfd = 17.5 Mcf/yr
Value of repair: ~$53/yr per leak (gas savings)
Plus avoided compliance penalties and ESG value
Program success metric: The leak occurrence rate (percentage of components found leaking in each survey) is the primary indicator of LDAR program effectiveness. Well-maintained facilities typically achieve leak rates below 1%. New facilities may start higher (2-5%) and improve as initial construction leaks are found and repaired.
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