GHG Emissions from Midstream Operations

1. Overview & Regulations

The oil and natural gas industry is a significant source of greenhouse gas emissions, with methane being the primary concern due to its high global warming potential. EPA's Greenhouse Gas Reporting Program (GHGRP) requires large emitters to report annually.

Regulatory Framework

Regulation	Scope	Threshold
40 CFR Part 98 Subpart W	Petroleum & Natural Gas Systems	25,000 MT CO2e/yr
40 CFR Part 98 Subpart C	General Stationary Fuel Combustion	25,000 MT CO2e/yr
NSPS OOOOa/b	New Source Performance Standards	Equipment-specific
EPA Methane Rule (2024)	Waste Emissions Charge (IRA Sec. 136)	Facility-level intensity

Subpart W Applicability

Subpart W applies to the following midstream industry segments:

• Gathering and Boosting: Wellhead to processing plant
• Natural Gas Processing: NGL extraction, fractionation, sweetening
• Transmission and Compression: Interstate/intrastate pipelines
• Underground Natural Gas Storage: Depleted reservoirs, salt caverns
• LNG Storage: Import/export terminals

Reporting Timeline

Milestone	Deadline
Data collection year	January 1 – December 31
e-GGRT submission	March 31 of following year
Data verification (if required)	Within 3 years
Record retention	3 years minimum

2. Emission Sources

Midstream facilities produce GHG emissions from six primary source categories. Each has distinct quantification methods under Subpart W.

Source Categories

Source	Primary GHG	Typical Contribution
Combustion	CO2, CH4, N2O	30–60% of facility total
Venting	CH4 (primary)	10–30%
Flaring	CO2 (primary), CH4 (slip)	5–20%
Fugitive	CH4 (primary)	5–15%
Pneumatic Devices	CH4	5–15%
Dehydrator Vents	CH4, VOCs	2–10%

Combustion Sources

Stationary combustion equipment includes reciprocating engines (compressor drivers), natural gas-fired heaters, line heaters, reboilers, and emergency generators. These produce CO2 as the dominant greenhouse gas from fuel oxidation, with small quantities of CH4 and N2O.

Venting Sources

Intentional releases of natural gas to the atmosphere occur during blowdowns, emergency relief events, tank flashing, and equipment depressurization for maintenance. Venting is the most potent GHG source per unit volume because methane is released directly without combustion.

Flaring Sources

Flares combust waste gas that cannot be economically recovered. While flaring converts most methane to CO2 (reducing GWP by 96%), the 2–5% uncombusted methane slip can be significant. EPA assumes 98% destruction efficiency as a default.

Fugitive Sources

Unintentional leaks from equipment components including valves, flanges, connectors, pump seals, compressor seals, and open-ended lines. EPA provides average emission factors by component type and service (gas, light liquid, heavy liquid).

Pneumatic Devices

Gas-driven pneumatic controllers and pumps use pressurized natural gas to actuate control valves. High-bleed devices emit approximately 37 scf/hr of methane continuously, while low-bleed devices emit only 1.4 scf/hr.

Dehydrator Vents

Glycol dehydration units produce methane emissions from the regenerator still column vent and flash gas. Flash gas emissions depend on the absorption pressure, circulation rate, and gas composition.

3. Calculation Methods

Combustion Emissions

Combustion emissions are calculated using fuel consumption and emission factors per unit of heat input:

Venting Emissions

Flaring Emissions

Fugitive Emissions (EPA Average Factor Method)

Pneumatic Device Emissions

4. Emission Factors

Combustion Emission Factors

Fuel	CO2 (kg/MMBtu)	CH4 (g/MMBtu)	N2O (g/MMBtu)
Natural Gas	53.06	1.0	0.1
Diesel / Distillate Oil	73.96	3.0	0.6
Propane	63.07	3.0	0.6
Residual Fuel Oil	75.10	3.0	0.6

Source: EPA 40 CFR Part 98 Subpart C, Table C-1/C-2

Fugitive Emission Factors (Gas Service)

Component Type	EF (kg/hr/component)	Annual per 100 Components (MT/yr)
Valves	0.0268	23.5
Connectors / Flanges	0.0006	0.53
Open-Ended Lines	0.0165	14.5
Pressure Relief Valves	0.0447	39.2
Pump Seals	0.0160	14.0
Compressor Seals	0.2360	206.7

Source: EPA Protocol for Equipment Leak Emission Estimates (EPA-453/R-95-017)

Pneumatic Device Emission Rates

Device Type	CH4 Rate (scf/hr)	Annual per Device (MT CH4/yr)
High-Bleed Controller	37.3	6.24
Low-Bleed Controller	1.39	0.23
Intermittent Controller	13.5	2.26

Source: EPA Subpart W, Table W-1A

5. Global Warming Potentials (GWP)

The Global Warming Potential converts non-CO2 greenhouse gases into CO2-equivalent units. GWP represents the relative warming effect of a gas compared to CO2 over a specified time horizon (typically 100 years).

GWP Comparison by IPCC Assessment

Gas	AR4 (2007)	AR5 (2014)	AR6 (2021)	20-Year GWP
CO2	1	1	1	1
CH4	25	28	29.8	80–84
N2O	298	265	273	265

Why Methane GWP Matters

Methane is a short-lived climate pollutant with a strong near-term warming effect. While its 100-year GWP is 25–30 times CO2, its 20-year GWP is approximately 80 times CO2. This means that methane reductions produce faster climate benefits than CO2 reductions of the same mass.

For a midstream facility venting 10 MSCF/day of methane:

GWP Basis	CO2e Impact (MT/yr)
AR4 (GWP=25)	~1,600
AR5 (GWP=28)	~1,790
20-Year (GWP=80)	~5,120

6. Emission Reduction Strategies

Midstream operators can significantly reduce GHG emissions through equipment upgrades, operational improvements, and leak detection programs. Many reductions also capture saleable natural gas, providing an economic return.

Combustion Reductions

• Engine upgrades: Replace rich-burn engines with lean-burn or electric drives (50–90% reduction)
• Waste heat recovery: Capture exhaust heat for process heating (10–20% fuel savings)
• Solar/wind power: Replace gas-fired generators at remote sites
• Electrification: Replace gas engines with electric motors where grid power is available

Venting Reductions

• Vapor recovery units (VRU): Capture tank and process vapors (95%+ reduction)
• Route to flare: If VRU not feasible, route vents to flare (98% conversion to CO2)
• Reduced-emission completions (green completions): Capture flowback gas during well completions
• Blowdown recovery: Capture compressor blowdowns to a low-pressure system

Fugitive Emission Reductions (LDAR)

LDAR Method	Detection Capability	Typical Reduction
Method 21 (EPA)	500–10,000 ppm	40–60%
OGI Camera (FLIR)	Visual detection	60–80%
Continuous Monitoring	Real-time sensors	70–90%
Aerial/Satellite	Facility-level screening	Identifies super-emitters

Pneumatic Device Conversions

• High-bleed to low-bleed: 96% reduction per device (37.3 to 1.39 scf/hr)
• Replace with electric: Zero direct methane emissions from actuator
• Instrument air systems: Use compressed air instead of natural gas supply

Dehydrator Vent Reductions

• Flash gas separator: Capture flash gas for fuel use (80–95% reduction)
• Condensers on still column: Recover heavy hydrocarbons and reduce vent volume
• Electric reboiler: Eliminate combustion emissions from reboiler

References

• EPA 40 CFR Part 98 — Mandatory Greenhouse Gas Reporting Rule
• EPA 40 CFR Part 98, Subpart W — Petroleum and Natural Gas Systems
• EPA 40 CFR Part 98, Subpart C — General Stationary Fuel Combustion
• API Compendium of GHG Emissions Methodologies for Oil & Gas Industry (2009)
• EPA AP-42, Chapter 3 — Stationary Internal Combustion Sources
• EPA Protocol for Equipment Leak Emission Estimates (EPA-453/R-95-017)
• IPCC Fifth Assessment Report (AR5) — Climate Change 2014
• IPCC Sixth Assessment Report (AR6) — Climate Change 2021