Patrick Foley

U.S. EPA - OECA
The Basics

• Inspections

– Problems Exist

• Oversteaming• Overaeration• Low BTU/scf

– Up to 100s‐1000s tons

excess emissions per flare

Insufficient Steam/Air:Smoke due to poor mixing‐Not enough oxygen

Good Combustion:Turbulent, Hot Flame

• Problem:

– Wastes money

• Wastes product and fuel

– Increases Emissions

• The Solution

– Reduce Flaring

• FGRS• Source Reduction

– New Flare Efficiency Metrics with Monitoring

• Net Heating Value (BTU/scf) of the gas in the combust

(NHVCZ)

• Lower Flammability Limit in the Combustion Zone (LFL

Flaring and Oversteaming
Elevated Flare

Vent

Stream

Gas Collection Header

Knockout

Drum

Drain

Purge

Gas

Liquid Seal

Flare Tip

Stack Seal

Flare Stack

To Fuel Gas System

or Product Recovery

Flare Gas

Recovery Compressor

GC

Vent Gas

Flow Meter

Sweep

Gas
PFTIR Flare Testing

• Flare radiance is the

spectral signal

• IR camera used to point the

PFTIR just outside the flare

combustion zone.

• IR spectrometer measures

compounds.





1   βα CZNHV

βα CZNHV CE









where α 

= 0.12, β

= ‐95
Enforcement Alert
Legal Bases for Injunctive Relief for Fla

Violations

• New Source Review violation: Either PSD or Nonatta

NSR

– Construction of new flares or new units tied into flares resulting i

significant emissions increase of VOC and SO2

– BACT/LAER could include flare gas recovery, volumetric caps, LFL/

98% combustion efficiency

• Failure to comply with Subparts J and Ja and Consen

– Violation of limitation on H2S concentration

– Often requires FGRS and other flare minimization steps

• Failure to comply with an emission limit and/or dest

combustion efficiency that is applicable to the Flare

– Permits (eg, INEOS/Addyston case) and SIPs
Legal Bases for Flaring Violations (con

• Failure to Operate the Flare in a manner consistent w

Air Pollution Control Practices for Minimizing Emissio

– NSPS 60.11 (d)

– NESHAP 61.12(c)

– MACT 63.6(e)(1)(i)

– Permits– SIPs

• Failure to Operate the Flare in Conformance with Design

– Permits, SIPs

• Failure to Monitor the Flare to Assure Operation in Accor

Design

– NSPS 60.18(d)

– MACT 63.11(b)(1)

– Individual standards in the NSPS and MACTs (eg., HON LDAR Closed Vent S

standard at 63.172 (e)(must monitor these “control devices to ensure tha

operated and maintained in conformance with their design”)

– Permits– SIPs
Marathon and BP Settlements

• Injunctive Relief

– Flare Minimization

• Flare Gas Recovery• “Cap” on Volumetric flow to the flare

– Flare Efficiency

• Steam & Vent Gas Flowmeters

• Gas Chromatography• NHVcz & S/VG ratio

• Penalty• Mitigation Projects & SEPs

– Fenceline Monitoring


Marathon and BP Injunctive Rel

Emissions Reductions

• For Marathon, flare efficiency and caps wi

in:

– VOC emission reductions greater than 5,000 T

and

– HAP emission reductions greater than 135 TP

• For BP, flare efficiency, flare gas recovery a

will result in:

– VOC emission reductions greater than 3090 T

– HAP emission reductions greater than 83 TPY

* All values estimated. Volume and composition of waste gas not monitored prev
Potential U.S. Refinery Flare VOC Emissions if Maratho

BP Flare Gas Volume, Composition and CE are Typi

Sensitivity Analysis Crude Capacity (bpd)

Total VOC Emissions

from Flares (ton/year)

U.S. Full CapacityWith CE Problems

17,787,714 98,000

50% U.S. CapacityWith CE Problems

8,893,857 49,000

25% U.S. CapacityWith CE Problems

4,446,929 24,000

10% U.S. CapacityWith CE Problems

1,778,771 10,000

1. U.S. crude capacity as of January 1, 2012, per Oil & Gas Journal.

99% of these emissions can be controlled through a flare

efficiency program. HAP content of flare gas is highly

variable, but can typically range from 0.5 to 3.0 %.
Flaring Settlements

Emissions Reductions and Cost Savin

• EPA is negotiating settlements with several compa

will result in VOC, HAP, and GHG emissions reducti

well as cost savings to the companies from recove

and reduced steam demand.

• Emissions reductions and cost savings are provided

– Per 1,000 barrels of crude feed;

– Per 1,000 pounds of crude feed;– Annually for a model refinery with 140,000 barrels pe

(BPD) of crude capacity.

• Estimated control costs and payback period are pr

for a model facility.
Per 1,000 Barrels Crude Fee

Baseline

Post‐

Implementation 

Flare Vent Gas Flow Rate(SCF/MBBL) 12,756 5,175 

VOC Emissions (LB/MBBL) 30 1.4 HAP Emissions (LB/MBBL) 0.81 0.07 

GHG Emissions (LB CO2e/MBBL) 1,743 655 

Vent Gas Lost Product Value($/MBBL) 119 41 Vent Gas Lost Fuel Value

($/MBBL) 42 18 Assist Steam Cost ($/MBBL) 16 3 
Per 1,000 Pounds Feed

Baseline

Post‐

Implementation 

Flare Vent Gas Flow Rate(SCF/MLB) 42 17 

VOC Emissions (LB/MLB) 0.099 0.004 

HAP Emissions (LB/MLB) 0.0027 0.0002 

GHG Emissions (LB CO2e/MLB) 5.7 2.1 

Vent Gas Lost Product Value($/MLB) 0.39 0.14 Vent Gas Lost Fuel Value ($/MLB) 0.14 0.06 Assist Steam Cost ($/MLB) 0.051 0.011 
140,000 BPD Refinery

42.8 mmlb/day Feed Plant

Baseline

Post‐

Implementation 

Flare Vent Gas Flow Rate

(MMSCF/YR) 660 270 

VOC Emissions (TON/YR) 780 40 HAP Emissions (TON/YR) 21 2 

GHG Emissions (TON CO2e/YR) 44,600 16,800 

Vent Gas Lost Product Value($/YR) 6,105,000 2,111,000 Vent Gas Lost Fuel Value

($/YR) 2,124,000 909,000 Assist Steam Cost ($/YR) 795,000 175,000 

1. 42.8 mmlb/day feed.
Control Costs and Payback Per

• For the 140,000 BPD model refinery, total installed costs 

– Flare monitoring and controls: $6,040,000;– Flare gas recovery compressors (2 × 62.5 MSCFH): $20,000,

• If vent gas is recovered as products, the savings from reco

and reduced steam demand are:

– Annual Savings: $4,614,000;

– Payback Period: 5.6 years.

• If vent gas is recovered as refinery fuel gas, the savings fr

recovered gas and reduced steam demand are:

– Annual Savings: $1,836,000;

– Payback Period: 14.2 years.

An Ounce of Prevention is Wor

Pound of Cure

• More money can be made from preven

the gas from entering the header in the 

place.

• Flare gas mapping combined with sourc

reduction often pays for itself.
Assumed Vent Gas Composit

Component Concentration (vol%)

Hydrogen 26.4Nitrogen 25.7Methane 25.3Ethane 3.7Ethylene 1.0

Propane & Propylene 8.0

Butane & Butenes 5.7

Pentane & Heavier 2.7
Assumed Product Values

Component Value

Hydrogen ($/MSCF) 3.33

Nitrogen ($/MSCF) 3.25

Fuel Gas ($/MMBTU)1 4.40

Propane & Propylene ($/GAL) 1.28

Butane & Butenes ($/GAL) 1.89Pentane & Heavier ($/GAL) 2.91Steam ($/MLB) 6.66

1 Methane, ethane, and ethylene assumed to be recovered as fuel gas.
AFPM and ACC

• AFPM and ACC met with EPA staff and OECA

(Enforcement) management in recent months.

• AFPM and ACC suggested that an alternative pat

traditional EPA enforcement would be preferred 

membership.

• EPA is considering a program to rapidly address

noncompliance in a more cooperative and exped

manner than traditional enforcement for a large 

the refining and petrochemical sectors.

• Time needed to develop and vet within EPA befo

details of the program are provided.
Alternative Program Issues

• Refineries and Olefins

– Easier to determine expectations

– Settlements completed or near completion that set expectations 

settlements

– Extensive ongoing and historical subpart J/Ja noncompliance at re

complication for alternative program entry

• Other Chemical Plants

– Batch and continuous

– Specialty products– High nitrogen purges, lowering value as a fuel

– Higher ratio of flared gas BTU to potential fuel sink BTU

– High purity concerns for product recovery

– Searching for commonality in flare gas flows, but may be case by 

subsector by subsector determination of FGRS expectations
Next Steps

• Develop entry qualifications for alternative p

• Develop requirements and timeline for altern

program.

• Seek approval of EPA management for altern

program.
Patrick Foley

U.S. EPA

Foley.Patrick@epa.gov