Respondent Description Order Type Date

Settlement Reached on 

Requiring Monitoring 

and Testing at Schott 

Metal Facility in Ohio

EPA and Schott Metal Products, Inc. agreed to a 

settlement resolving claims for alleged violations of 

section 3013 of the Resource Conservation and 

Recovery Act (RCRA), which calls for completion of 

activities under and approved work plan for monitoring 

and testing of soil and groundwater contamination at 

the Schott Metal facility and for payment of a 

$375,000 civil penalty. 

Consent 

Decree 07/22/2013 

XTO Energy, Inc. 

Settlement

The U.S. Environmental Protection Agency and the 

U.S. Department of Justice announced a settlement 

with XTO Energy Inc. to resolve an alleged violation 

of the Clean Water Act (CWA) related to the discharge 

of stored wastewater from natural gas exploration and 

production activities, commonly known as fracking, in 

Penn Township, Pa. 

Consent 

Decree 07/18/2013 

Cape Fear/Wilmington, 

North Carolina 

Settlement

(ATLANTA, GA - July 11, 2013) - The U.S. 

Environmental Protection Agency (EPA) today 

announced a Clean Water Act (CWA) settlement with 

the City of Wilmington, New Hanover County and the 

Cape Fear Public Utility Authority (Authority) in 

North Carolina. The proposed settlement set forth in a 

consent decree will resolve these parties’ liability for 

violations of the CWA, including unauthorized 

overflows of untreated raw sewage. 

Consent 

Decree 07/11/2013 

Holcim (US) Inc. 

Settlement

The U.S. Environmental Protection Agency (EPA) and 

the U.S. Justice Department today announced a Clean 

Air Act settlement with Holcim (US) Inc. (Holcim) and 

former owner St. Lawrence Cement Company, LLC, 

that covers the Portland cement manufacturing facility 

in Hagerstown, Maryland. Holcim has agreed to invest 

approximately $20 million or more to resolve 

violations of the Clean Air Act. 

Consent 

Decree 07/11/2013 

Shell Deer Park 

Settlement (Flaring)

The Department of Justice and the U.S. Environmental 

Protection Agency (EPA) announced today that Shell 

Oil and affiliated partnerships (Shell) have agreed to 

resolve alleged violations of the Clean Air Act at a 

large refinery and chemical plant in Deer Park, Texas 

by spending at least $115 million to control harmful air 

pollution from industrial flares and other processes, 

and by paying a $2.6 million civil penalty. 

Consent 

Decree 07/10/2013 

Settlement Approved to 

Complete Cleanup at 

Cabot/Koppers Site in 

Florida

A RD/RA consent decree between the United States 

and Beazer East, Inc. was approved by the United 

States District Court for the Northern District of 

Florida, Gainesville Division, to complete cleanup 

work at the Cabot/Koppers Superfund site in 

Gainesville, Fla. at an estimated cost of $55 million. 

Consent 

Decree 07/09/2013 

Civil Cases and Settlements | Enforcement | US EPA Page 21 of 104

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Enforcement

Shell Deer Park Settlement

(Washington, DC - July 10, 2013) The Department of Justice and the U.S. Environmental Protection 

Agency (EPA) announced today that Shell Oil and affiliated partnerships (Shell) have agreed to resolve 

alleged violations of the Clean Air Act at a large refinery and chemical plant in Deer Park, Texas by 

spending at least $115 million to control harmful air pollution from industrial flares and other processes, 

and by paying a $2.6 million civil penalty. Shell has agreed to spend $1 million on a state-of-the-art system 

to monitor benzene levels at the fenceline of the refinery and chemical plant near a residential 

neighborhood and school and to make the data available to the public through a website. 

On this page:

Settlement Resources

• Press Release

• Consent Decree

• Overview of Company and Location of Facilities

• Violations

• Injunctive Relief

• Environmental Mitigation Projects

• Supplemental Environmental Projects

• Pollutant Reductions 

• Health and Environmental Effects 

• Civil Penalty

• City of Houston

• Comment Period

• Contacts

• More Information

Overview of Company and Location of Facilities

Shell Deer Park Settlement | Enforcement | US EPA Page 1 of 5

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The facilities that are the subject of this settlement are an integrated refinery and chemical plant located in 

the City of Deer Park, Texas. Deer Park is situated about 15 miles southeast of Houston. Shell Oil 

Company operates the refinery, which is owned by Deer Park Refining LP. Shell Chemical LP is the entity 

that owns and operates the chemical plant.

The refinery processes approximately 330,000 barrels per day of crude oil, which makes it the eleventh 

largest refinery in the United States. It produces a variety of refined products, including gasoline, jet fuel 

and diesel. The chemical plant manufactures base chemicals that are sold to other chemical companies that 

transform them into thousands of consumer products, ranging from plastics to building materials. In total, 

the chemical plant produces approximately 8000 tons per day of petrochemical and chemical products, 

such as ethylene, propylene, butylene, isoprene, butadiene, benzene, toluene, xylene, phenol, acetone and 

cumene. Both the chemical plant and the refinery operate 24 hours a day, 365 days a year.

Violations

The complaint alleges violations of Clean Air Act requirements at SDP’s twelve steam assisted flares that 

resulted in excess emissions of volatile organic compounds (VOCs) and various hazardous air pollutants 

(HAPs) including benzene. The complaint allegations include violations of:

• New Source Review/Prevention of Significant Deterioration (NSR/PSD) and Minor New Source 

Review, 40 C.F.R. Parts 51 and 52

• New Source Performance Standards (NSPS), 40 C.F.R. Part 60, Subparts A, J, VV, VVa, GGG, and 

GGGa

• National Emission Standards for Hazardous Air Pollutants (NESHAP), 40 C.F.R. Part 63, Subparts 

A, CC, G, FF, and UUU

• Title V and the Title V permits at SDP’s facilities

• Texas State Implementation Plan (SIP) requirements

• Comprehensive Environmental Response, Compensation and Liability Act (CERCLA), 42 U.S.C. § 

9603(a), and the Emergency Planning and Community Right-to-Know Act (EPCRA), 42 U.S.C. § 

11004(b)

Injunctive Relief

The consent decree requires the following actions to resolve the CAA claims:

Flare Minimization/Caps/Flare Gas Recovery System (FGRS) Sizing

• Submit and implement a waste gas minimization plan which is a very detailed plan for reducing 

waste gas to flares. Update the plan on a yearly basis. Plan is enforceable.

• Undertake a root cause analysis and implement corrective action for “Reportable Flaring 

Incidents” (i.e., greater than 500 lb/day SO2 or 500,000 standard cubic feet per day (“scfd”) waste 

gas flow).

• At the Refinery take a limit on flaring, i.e., flaring caps 

◦ Facility-wide 30-day rolling average limit of 2,455,944 scfd.

◦ Facility-wide 365 day rolling average limit of 1,637,296 scfd.

• At the Chemical Plant install FGRS capable of eliminating base load/routine flaring and will at 

minimum be capable of capturing 6.5 million scfd of process gas.

• All of SDP’s FGRSs will be required to be available for operation a high percentage of time.

Shell Deer Park Settlement | Enforcement | US EPA Page 2 of 5

http://www.epa.gov/enforcement/shell-deer-park-settlement 12/29/2015
Flare Efficiency

• Comply with current regulatory standards.

• Install and operate the following monitoring systems and equipment: Vent Gas Flow Meter; Steam 

Flow Meter; Steam Control Equipment; Gas Chromatograph or a Net Heating Value Analyzer; and a 

Meteorological Station.

• Automate the control of Supplemental Gas (i.e. gas used to increase the net heating value of the gas 

being flared) and steam addition in order to achieve high combustion efficiency.

• Comply with the following limits: 

◦ For 9 flares in regular use (except the Ground Flare): Net Heating Value in the Combustion 

Zone Gas (“NHVcz”) ≥ NHVcz-limit (which is calculated dynamically every 15 minutes).

◦ For the Ground Flare use: NHVcz ≥ 500 BTU/scf (static limit).

◦ For 3 flares in temporary use: NHVcz ≥ 355 BTU/scf (static limit).

• Steam/Vent Gas ratio “S/VG” ≤ 3.0.

• Add supplemental gas when wind effect makes the flare flame unstable.

• 98% Combustion Efficiency.

Environmental Mitigation Projects

SDP will implement three mitigation projects valued at between $15 and $60 million. SDP will: 

(1) significantly modify its wastewater treatment plant to reduce emissions of VOCs; (2) control VOC 

emissions from certain tanks by replacing two old tanks, repairing one tank, and engaging in an innovative 

bi-weekly infrared-camera imaging program for fifteen other tanks; and (3) control emissions of 

hazardous air pollutants (“HAPs”) and VOCs at its benzene production unit through enhanced monitoring 

and repair practices. When fully implemented, EPA estimates that these projects will reduce VOC 

emissions by at least 300 tons per year.

Supplemental Environmental Projects (SEPs)

SDP will perform two SEPs: it will install and operate a state-of-the-art air monitoring station at its fence 

line at an approximate cost of $1 million, and it will reduce diesel emissions from old, publicly-owned 

vehicles in the vicinity of the Deer Park complex through retrofit technology at a cost of $200,000.

Pollutant Reductions

When fully implemented, the new controls and requirements under the Consent Decree are estimated to 

reduce emissions by over 4,500 tons per year (tpy) of the following pollutants, as follows:

• SO2 by approximately 2,412 tpy

• VOCs by approximately 1,838 tpy, of which approximately 264 tpy are Hazardous Air Pollutants 

• Additional reductions of PM, PM10, PMTOTAL, carbon monoxide (CO) and H2S

In addition, the controls required by the Consent Decree will result in a reduction of GHGs by 

approximately 261,033 tpy (as carbon dioxide equivalents, or CO2e).

Health and Environmental Benefits

• Nitrogen Oxides – Nitrogen oxides can cause ground-level ozone, acid rain, particulate matter, 

global warming, water quality deterioration, and visual impairment. Nitrogen oxides play a major 

Shell Deer Park Settlement | Enforcement | US EPA Page 3 of 5

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role, with volatile organic chemicals, in the atmospheric reactions that produce ozone. Children, 

people with lung diseases such as asthma, and people who work or exercise outside are susceptible 

to adverse effects such as damage to lung tissue and reduction in lung function.

• Sulfur Dioxide – High concentrations of SO2 affect breathing and may aggravate existing 

respiratory and cardiovascular disease. Sensitive populations include asthmatics, individuals with 

bronchitis or emphysema, children and the elderly. Sulfur dioxide is also a primary contributor to 

acid deposition, or acid rain.

• Volatile Organic Compounds - VOCs, along with NOx, play a major role in the atmospheric 

reactions that produce ozone, which is the primary constituent of smog. People with lung disease, 

children, older adults, and people who are active can be affected when ozone levels are unhealthy. 

Ground-level ozone exposure is linked to a variety of short-term health problems, including lung 

irritation and difficulty breathing, as well as long-term problems, such as permanent lung damage 

from repeated exposure, aggravated asthma, reduced lung capacity, and increased susceptibility to 

respiratory illnesses such as pneumonia and bronchitis.

• Benzene - Acute (short-term) inhalation exposure of humans to benzene may cause drowsiness, 

dizziness, headaches, as well as eye, skin, and respiratory tract irritation, and, at high levels, 

unconsciousness. Chronic (long-term) inhalation exposure has caused various disorders in the 

blood, including reduced numbers of red blood cells and anemia in occupational settings. 

Reproductive effects have been reported for women exposed by inhalation to high levels, and 

adverse effects on the developing fetus have been observed in animal tests. Increased incidences of 

leukemia have been observed in humans occupationally exposed to benzene. EPA has classified 

benzene as a Group A human carcinogen.

• Greenhouse Gases – The release of GHGs into the atmosphere traps heat. The continued release of 

GHGs at or above the current rate will increase average temperatures around the globe. Increases in 

global temperatures will most likely change our planet’s climate in ways that will have significant 

long-term effects on people and the environment.

• Particulate Matter – PM, especially fine particles, contain microscopic solids or liquid droplets that 

are so small that they can get deep into the lungs and cause serious health problems. PM is linked to 

a variety of problems, including increased respiratory symptoms such as irritation of the airways, 

coughing, or difficulty breathing, decreased lung function, aggravated asthma, and premature death 

in people with heart or lung disease.

Civil Penalty

SDP will pay a civil penalty of $2.6 million.

City of Houston

With funding from an EPA grant, the City of Houston with assistance from EPA conducted differential 

absorption lidar (DIAL) benzene and VOC ambient air testing at Shell's Deer Park Refinery and Chemical 

Plant. The campaign was conducted in early 2010. The DIAL data helped identify specific areas of 

concern within Shell's facilities. Many areas so identified will be addressed by the mitigation projects 

included in the settlement in order to reduce emissions of benzene and VOC. EPA is grateful for the City 

of Houston's contribution.

Shell Deer Park Settlement | Enforcement | US EPA Page 4 of 5

http://www.epa.gov/enforcement/shell-deer-park-settlement 12/29/2015
Last updated on September 1, 2015

Comment Period

The proposed settlement is lodged in the U.S. District Court for the Southern District of Texas. The 

consent decree will be subject to a 30-day public comment period and final court approval. Information on 

submitting comments is available at the Department of Justice website.

Contacts

Robert Parrish 

Attorney

U.S. Environmental Protection Agency (2242A) 

1200 Pennsylvania Ave., N.W. 

Washington, DC 20460-0001 

(202) 564-6946

Robert Parrish (parrish.robert@epa.gov)

Patrick W. Foley 

Senior Environmental Engineer 

U.S. Environmental Protection Agency (2242A) 

1200 Pennsylvania Ave., N.W. 

Washington, DC 20460-0001 

(202) 564-7978 

Patrick Foley (foley.patrick@epa.gov)

More information

• EPA’s Air Toxics National Enforcement Initiative

• Enforcement Alert: EPA Enforcement Targets Flaring Efficiency Violations (August 2012)

Prior enforcement settlements related to industrial flaring

• BP North America

• Marathon Petroleum Company

• CountryMark Refining and Logistics

Shell Deer Park Settlement | Enforcement | US EPA Page 5 of 5

http://www.epa.gov/enforcement/shell-deer-park-settlement 12/29/2015
Newsroom

News Releases By Date

Shell Oil To Spend Over $115 Million to Reduce Harmful Air Pollution at 

Houston Area Refinery And Chemical Plant 

Release Date: 07/10/2013

Contact Information: Dale Kemery (News media only) kemery.dale@epa.gov 202-564-7839 202-564-4355; En español: Lina 

Younes younes.lina@epa.gov 202-564-9924 202-564-4355

WASHINGTON - The Department of Justice and the U.S. Environmental Protection Agency (EPA) announced 

today that Shell Oil and affiliated partnerships (Shell) have agreed to resolve alleged violations of the Clean Air 

Act at a large refinery and chemical plant in Deer Park, Texas by spending at least $115 million to control 

harmful air pollution from industrial flares and other processes, and by paying a $2.6 million civil penalty. Shell 

has agreed to spend $1 million on a state-of-the-art system to monitor benzene levels at the fenceline of the 

refinery and chemical plant near a residential neighborhood and school and to make the data available to the 

public through a website. 

Shell will spend $100 million on innovative technology to reduce harmful air pollution from industrial flares, 

which are devices used to burn waste gases. Shell is required to take the following actions to improve flaring 

operations: minimize flaring by recovering and recycling waste gases (which may then be reused by Shell as a 

fuel or product); comply with limitations on how much waste gas can be burned in a flare (flare caps); and install 

and operate instruments and monitoring systems to ensure that gases that are sent to flares are burned with 

98% efficiency. Shell’s agreement to recover and recycle waste gases (flare gas recovery) at its chemical plant 

is a first of its kind. 

Once fully implemented, the pollution controls required by the settlement will reduce harmful air emissions of 

sulfur dioxide, volatile organic compounds (VOCs), including benzene, and other hazardous air pollutants by an 

estimated 4,550 tons or more per year. These controls will also reduce emissions of greenhouse gases by 

approximately 260,000 tons per year. 

“The innovative emission controls required by today’s settlement will cut harmful air pollution in communities 

near Houston,” said Cynthia Giles, assistant administrator of EPA’s Office of Enforcement and Compliance 

Assurance. “This case is part of EPA’s nationwide enforcement effort to protect fenceline neighborhoods by 

significantly reducing toxic pollution from flares and making information about pollution quickly available to 

affected communities.”

“This settlement will result in substantial reductions in toxic air pollution through state of the art technology and 

increased efficiencies at the Deer Park plant,” said Acting Assistant Attorney General Robert G. Dreher of the 

Justice Department’s Environment and Natural Resources Division. “This agreement will bring Shell Oil’s 

refinery and chemical plant in Deer Park into compliance with the nation’s Clean Air Act and result in cleaner, 

healthier air for residents in the local communities for many years to come.”

The settlement was filed at the same time DOJ filed a complaint on behalf of EPA

alleging, among other things, that the company improperly operated its 12 steam-assisted flaring devices in 

such a way that excess VOCs, including benzene and other hazardous air pollutants, were emitted. 

In addition to reducing pollution from flares, Shell will significantly modify its wastewater treatment plant; replace 

and repair tanks as necessary; inspect tanks biweekly with an infrared camera to better identify potential 

integrity problems that may lead to leaks; and implement enhanced monitoring and repair practices at the 

benzene production unit. When fully implemented, these specific projects are estimated to cost between $15 

and $60 million.

Also, in a second project to benefit the community, Shell has agreed to spend $200,000 on retrofit technology to 

reduce diesel emissions from government-owned vehicles which operate in the vicinity of the Deer Park 

complex. 

These actions will cut emissions of pollutants that can cause significant harm to public health. Exposure to high 

concentrations of sulfur dioxide can affect breathing and aggravate existing respiratory and cardiovascular 

disease. VOCs are a key component in the formation of smog or ground-level ozone, a pollutant that irritates 

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the lungs, exacerbates diseases such as asthma, and can increase susceptibility to respiratory illnesses, such 

as pneumonia and bronchitis. Chronic exposure to benzene, which EPA classifies as a carcinogen, can cause 

numerous health impacts, including leukemia and adverse reproductive effects in women. 

Today’s settlement is part of EPA’s national effort to reduce emissions of toxic air pollutants, with a particular 

focus on industrial flares. These requirements focus on reducing the amount of waste gas sent to flares and on 

improving flare operations, both of which work to reduce toxic emissions. Improper operation of an industrial 

flare can send hundreds of tons of hazardous air pollutants into the air. The more waste gas a company sends 

to a flare, the more pollution occurs. The less efficient a flare is in burning waste gas, the more pollution occurs. 

EPA wants companies to flare less, and when they do flare, to fully burn the harmful chemicals found in the 

waste gas. 

Shell, which is headquartered in Houston, processes approximately 330,000 barrels per day of crude oil at its 

Deer Park facility, making it the 11th largest refinery in the United States. In addition, the Deer Park chemical 

plant produces approximately 8,000 tons per day of products that include ethylene, benzene, toluene, xylene, 

phenol, and acetone. Both the chemical plant and the refinery operate 24 hours a day, 365 days a year.

The consent decree, lodged in the Southern District Court of Texas, is subject to a 30-day public comment 

period and court approval. The consent decree will be available for viewing at 

http://www.justice.gov/enrd/Consent_Decrees.html. The claims resolved by the settlement are allegations only, 

and there has been no determination of liability.

More information about the settlement:

www.epa.gov/enforcement/air/cases/sdp.html

More information about EPA’s Air Toxics National Enforcement Initiative:

http://www.epa.gov/compliance/data/planning/initiatives/2011airtoxics.html

Prior enforcement settlements related to industrial flaring:

BP North America:

http://www.epa.gov/compliance/resources/cases/civil/caa/bp-whiting.html

Marathon Petroleum Company:

http://yosemite.epa.gov/opa/admpress.nsf/2467feca60368729852573590040443d/e841a5bbc6dd1082852579d7

OpenDocument&Highlight=2,Marathon

CountryMark Refining and Logistics:

http://yosemite.epa.gov/opa/admpress.nsf/2467feca60368729852573590040443d/b511e565ba2af7f985257b200

OpenDocument&Highlight=2,CountryMark

Enforcement Alert: EPA Enforcement Targets Flaring Efficiency Violations (August 2012): 

http://www.epa.gov/enforcement/air/documents/newsletters/flaringviolations.pdf

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Last updated on June 15, 2015

Enforcement

Consent Decree: Shell Deer Park 

This is the consent decree and the settlement page for Shell Deer Park.

You will need Adobe Reader to view some of the files on this page. See EPA’s About PDF page to 

learn more.

• Shell Deer Park Consent Decree (PDF) (250 pp, 7 MB)

Consent Decree: Shell Deer Park | Enforcement | US EPA Page 1 of 1

http://www.epa.gov/enforcement/consent-decree-shell-deer-park 12/29/2015
__________________________________________ 

 

 

 

 

 

 

 

 

 

Case 4:13-cv-02009 Document 2-1 Filed in TXSD on 07/10/13 Page 1 of 121 

IN THE UNITED STATES DISTRICT COURT
 

FOR THE SOUTHERN DISTRICT OF TEXAS
 

) 

UNITED STATES OF AMERICA, ) 

) 

Plaintiff, ) 

) 

v. ) No. 4:13-cv-2009 

)
 

SHELL OIL COMPANY, DEER PARK )
 

REFINING LIMITED PARTNERSHIP, and )
 

SHELL CHEMICAL LP, )
 

)
 

Defendants. )
 

)
 

_________________________________________ ) 
 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Case 4:13-cv-02009 Document 2-1 Filed in TXSD on 07/10/13 Page 2 of 121 

TABLE OF CONTENTS
 

I.	 JURISDICTION AND VENUE ...............................................................................................5
 

II. APPLICABILITY .....................................................................................................................6
 

III. DEFINITIONS.........................................................................................................................8
 

IV. CIVIL PENALTY .................................................................................................................24
 

V.	 COMPLIANCE REQUIREMENTS .......................................................................................25
 

A.	 Instrumentation and Monitoring Systems ..........................................................................25
 

B.	 Determining Whether a Covered Flare that has a Water Seal
 

Is not Receiving Potentially Recoverable Gas Flow..........................................................30
 

C.	 Waste Gas Minimization ....................................................................................................31
 

D.	 Flare Gas Recovery Systems at the SDP Refinery ............................................................38
 

E.	 Flaring Limitations at the Refinery ....................................................................................41
 

F.	 Flare Gas Recovery System at the Olefins Flares of the SDP Chemical Plant ..................46
 

G.	 Limitations on Flaring at the A&S and HIPA Flares of the SDP Chemical Plant.............51
 

H.	 Flare Combustion Efficiency .............................................................................................52
 

I.	 NSPS Subpart A, J, and Ja Applicability............................................................................64
 

J.	 Eliminating Fuel Gas Flow from the SDP Refinery to the SDP Chemical Plant 

Covered Flares ....................................................................................................................64
 

K.	 Incorporation of Consent Decree Requirements into Federally
 

Enforceable Permits ...........................................................................................................65
 

VI. EMISSION CREDIT GENERATION ..................................................................................66
 

VII. MITIGATION PROJECTS ..................................................................................................68
 

VIII. SUPPLEMENTAL ENVIRONMENTAL PROJECTS......................................................69
 

IX. REPORTING REQUIREMENTS .........................................................................................73
 

ii 
 

 

 

 

 

 

 

Case 4:13-cv-02009 Document 2-1 Filed in TXSD on 07/10/13 Page 3 of 121 

X. STIPULATED PENALTIES ..................................................................................................77
 

XI. FORCE MAJEURE ...............................................................................................................87
 

XII. DISPUTE RESOLUTION ...................................................................................................90
 

A. For All Disputes Except those Arising Under Subparagraphs 43.c and 46.c ...................90
 

B. For Disputes Arising Under Subparagraphs 43.c and 46.c ...............................................92
 

XIII. INFORMATION COLLECTION AND RETENTION .....................................................92
 

XIV. EFFECT OF SETTLEMENT/RESERVATION OF RIGHTS...........................................94
 

XV. COSTS ...............................................................................................................................102
 

XVI. NOTICES..........................................................................................................................102
 

XVII. EFFECTIVE DATE ........................................................................................................104
 

XVIII. RETENTION OF JURISDICTION ...............................................................................105
 

XIX. MODIFICATION .............................................................................................................105
 

XX. TERMINATION ................................................................................................................105
 

XXI. PUBLIC PARTICIPATION .............................................................................................107
 

XXII. SIGNATORIES/SERVICE .............................................................................................108
 

XXIII. INTEGRATION.............................................................................................................108
 

XXIV. FINAL JUDGMENT .....................................................................................................109
 

iii 
 

 

 

 

 

Case 4:13-cv-02009 Document 2-1 Filed in TXSD on 07/10/13 Page 4 of 121 

TABLES OF APPENDICES 

TABLE 1 

NUMBER ABBREVIATION DESCRIPTION 

1.1 S-Drwgs Drawings Illustrating Lower, Center, and Upper Steam 

Injection in Various Types of Flare Tips 

1.2 Gen-Eq General Equations 

1.3 LFL Calculating NHVcz-limit and NHVcz for Steam-Assisted Flares 

1.4 Malf-Pol EPA’s Policy on Excess Emissions during Malfunctions, 

Startup, and Shutdown 

1.5 MFR-Eq Calculating Momentum Flux Ratio 

1.6 Tip-Area-Eq Calculating the Unobstructed Cross Sectional Area of Various 

Types of Flare Tips 

1.7 G-Drwg Depiction of Gases Associated with Steam-Assisted Flares 

1.8 Flr-Data-Rpt Outline of Requirements for the Flare Data and Initial 

Monitoring Systems Report 

1.9 GC-Cmpnds List of Compounds a Gas Chromatograph must be Capable of 

Speciating 

1.10 Tech-Specs Equipment and Instrumentation Technical Specifications and 

Quality Assurance/Quality Control Requirements 

1.11 WG-Map Waste Gas Mapping: Level of Detail Needed to Show Main 

Headers and Process Unit Headers 

1.12 DWDF-Drwgs Representations of Discontinuous Wake Dominated Flow 

1.13 Stips-Calc 

Calculating the Amount of Stipulated Penalties Due for 

Violating Limitations on Flaring when the Stipulated 

Penalties are Based on Excess VOC and SO2 Emitted 

1.14 Nlsn-Cmplxty 

Equations and Methodology to Calculate Refinery-Specific 

Complexity and Industry-Average Complexity using Nelson 

Complexity Index 

iv 
 

Case 4:13-cv-02009 Document 2-1 Filed in TXSD on 07/10/13 Page 5 of 121 

TABLE 2
 

NUMBER ABBREVIATION DESCRIPTION 

2.1 SDP-Cmplnc-Sch Covered Flares and Applicability Dates for Certain Consent 

Decree Requirements 

2.2 Intentionally left 

blank Intentionally left blank 

2.3 FLR-Limit-Calc Methodology for Calculating Refinery Flaring Limitation 

(including SDP’s Form EIA-820 for Report Year 2012) 

2.4 FGRS-%-Rcvy Calculation of Olefins FGRS Estimated Percent Recovery 

2.5 HIPA-Emssns 

Methodology for Calculating the 365-day Rolling Sum 

Emissions of Volatile Organic Compounds from the HIPA 

Flare 

2.6 Mitig-NET Mitigation Project at the North Effluent Treater 

2.7 Mitig-Tank Mitigation Project at Certain Tanks 

2.8 Mitig-ACU/BEU Mitigation Project at the ACU and BEU 

2.9 SEP-Mntring Fence Line Monitoring Supplemental Environmental Project 

2.10 SEP-Diesel Diesel Retrofit Supplemental Environmental Project 

v 
 

 

 

 

 

 

 

 

 

 

 

 

 

Case 4:13-cv-02009 Document 2-1 Filed in TXSD on 07/10/13 Page 6 of 121 

CONSENT DECREE 

WHEREAS Plaintiff the United States of America (“United States”), on behalf of the 

United States Environmental Protection Agency (“EPA”), has filed a complaint against 

Defendants Shell Oil Company (“Shell Oil”), Deer Park Refining Limited Partnership (“Deer 

Park Refining”), and Shell Chemical LP (“Shell Chemical”) (collectively “SDP”), concurrently 

with the lodging of this Consent Decree, for alleged environmental violations at Shell Oil’s and 

Deer Park Refining’s petroleum refinery (“SDP Refinery”) and at Shell Chemical’s chemical 

plant (“SDP Chemical Plant”) (collectively “Covered Facilities”), both located in Deer Park, 

Texas; 

WHEREAS, on information and belief, the United States alleges that SDP has violated 

and/or continues to violate, at the Covered Facilities, one or more of the following statutory and 

regulatory provisions: 

a. The Prevention of Significant Deterioration (“PSD”) requirements found 

in 42 U.S.C. § 7475 and 40 C.F.R. §§ 52.21(a)(2)(iii) and 52.21(j)– 

52.21(r)(5); 

b. The Non-Attainment New Source Review (“NNSR”) requirements found 

in 42 U.S.C. §§ 7502(c)(5), 7503(a)–(c) and 40 C.F.R. Part 51, 

Appendix S, Part IV, Conditions 1–4; 

c. The federally enforceable Minor New Source Review (“Minor NSR”) 

requirements adopted and implemented by the Relevant States in their 

State Implementation Plans (“SIPs”) pursuant to 42 U.S.C. 

§ 7410(a)(2)(C) and 40 C.F.R. §§ 51.160–51.164; 

d. The New Source Performance Standards (“NSPS”) promulgated at 

40 C.F.R. Part 60, Subparts A, J, VV, VVa, GGG, and GGGa, pursuant to 

Section 111 of the CAA, 42 U.S.C. § 7411; 

e. The National Emission Standards for Hazardous Air Pollutants 

(“NESHAPs”) promulgated at 40 C.F.R. Part 61, Subparts A and FF and 

40 C.F.R. Part 63, Subparts A, G, CC, FF, and UUU, pursuant to 

Section 112 of the CAA, 42 U.S.C. § 7412; 
 

 

 

 

 

Case 4:13-cv-02009 Document 2-1 Filed in TXSD on 07/10/13 Page 7 of 121 

f.	 The requirements of Title V of the CAA found at 42 U.S.C. §§ 7661a(a), 

7661b(c), 7661c(a); and 40 C.F.R. §§ 70.1(b), 70.5(a) and (b), 70.6(a) and 

(c), and 70.7(b); 

g.	 The portions of the Title V permits for the Covered Facilities that adopt, 

incorporate, or implement the provisions cited in a–e and h–i; 

h.	 The federally enforceable Texas SIP provisions that incorporate, adopt, 

and/or implement the federal requirements listed in a–b and d–f; and 

i.	 Additional, federally enforceable Texas SIP regulations. 

WHEREAS SDP denies that it has violated and/or continues to violate the foregoing 

statutory and regulatory requirements and denies any liability to the United States arising out of 

the transactions or occurrences alleged in the Complaint; 

WHEREAS SDP previously agreed, under a prior Consent Decree, to comply with 

40 C.F.R. Part 60, Subpart J, at certain Flares at the SDP Refinery and has installed, in 

compliance with that requirement and the requirements of this Decree, a Flare Gas Recovery 

System (“FGRS”) at an estimated total cost of approximately $90 million; 

WHEREAS, pursuant to this Decree, SDP has agreed to install a FGRS at the SDP 

Chemical Plant and to install other equipment to reroute, recover, and minimize Waste Gas flows 

at both the SDP Refinery and SDP Chemical Plant at an estimated total cost of approximately 

$90 million; 

WHEREAS, for purposes of complying with rules in the State of Texas for limiting 

emissions of highly reactive Volatile Organic Compounds, SDP, prior to the commencement of 

negotiations in this matter, installed Vent Gas flow meters and gas chromatographs on Flares 

designated in this Consent Decree as “Regular-Use” Flares, and, in addition, from 2008 through 

the Date of Lodging of this Consent Decree, spent more than $9.5 million to improve 

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combustion efficiency and reduce emissions from Flares, and projects that it will spend another 

$.5 million on these efforts; 

WHEREAS SDP estimates that the mitigation projects required pursuant to Section VII 

of this Decree will cost up to $60 million; 

WHEREAS SDP estimates that the Supplemental Environmental Projects required 

pursuant to Section VIII of this Decree will cost approximately $1.2 million; 

WHEREAS, between 2008 and full implementation of this Decree, EPA estimates that 

emissions from the twelve flares covered by this Consent Decree (“Covered Flares”) will be 

reduced by approximately the following amounts (in “tons per year” or “TPY”): 

Pollutant 2008–through implementation 

Volatile Organic Compounds (“VOCs”) 1,838 TPY 

Carbon Dioxide Equivalents (“CO2e”) 261,033 TPY 

Hazardous Air Pollutants (“HAPs”) 264 TPY 

Sulfur Dioxide (“SO2”) 2,412 TPY 

WHEREAS, between 2008 and full implementation of this Consent Decree, emissions of 

hydrogen sulfide (“H2S”) and carbon monoxide (“CO”) from the Covered Flares also will be 

reduced; 

WHEREAS EPA estimates that emissions of VOCs will be reduced by approximately 

300 TPY when the mitigation projects required in Section VII of this Consent Decree are fully 

implemented; 

WHEREAS SDP intends to convert the flare known as the A&S Flare, which is located at 

SDP’s Chemical Plant, into a Temporary-Use Flare (as that term is defined in this Consent 

Decree) and to redirect all gases from it to a flare known as the HIPA Flare, also located at 

SDP’s Chemical Plant; 

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WHEREAS SDP has demonstrated that even after the redirection of the gas flow from 

the A&S Flare to the HIPA Flare, the HIPA Flare will primarily serve intermittent loading 

operations and the gas directed to the HIPA Flare will contain high levels of inerts relative to 

volatile organic compounds, thus making a mass limit of volatile organic compounds from the 

HIPA Flare an appropriate emissions limit; 

WHEREAS SDP has demonstrated that the A&S Flare (after conversion) and the Flares 

known as the South Property Flare and the CCU Flare will be Temporary-Use Flares; 

WHEREAS, prior to the Date of Lodging of this Consent Decree, SDP represented that it 

completed a project to eliminate a connection between the Girbotol Flare (located at the SDP 

Refinery) and the A&S and HIPA Flares (located SDP Chemical Plant), and, pursuant to 

Subsection V.J of this Consent Decree, SDP has agreed to undertake other actions to discover 

and eliminate all connections from the SDP Refinery to the SDP Chemical Plant Covered Flares 

that potentially allow Fuel Gas flow; 

WHEREAS, by entering into this Consent Decree, SDP has indicated that it is committed 

to continuing to proactively reduce emissions from its Flares; 

WHEREAS this Consent Decree is intended to represent a comprehensive resolution of 

the claims alleged in the Complaint and the claims resolved through Section XIV (Effect of 

Settlement) and to ensure that when the compliance measures required by this Decree have been 

fully implemented, each Covered Flare will be operated and maintained to prevent a recurrence 

of the violations alleged in the Complaint and the violations resolved through Section XIV 

(Effect of Settlement); 

WHEREAS the United States anticipates that the specific and comprehensive compliance 

measures set forth in this Consent Decree, which are subject to a reasonable timetable for 

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Case 4:13-cv-02009 Document 2-1 Filed in TXSD on 07/10/13 Page 10 of 121 

implementation, will result in the cessation of the violations alleged in the Complaint and the 

violations resolved through Section XIV (Effect of Settlement); 

WHEREAS, the United States and SDP (the “Parties”) recognize, and this Court by 

entering this Consent Decree finds, that this Consent Decree has been negotiated by the Parties in 

good faith and will avoid litigation between the Parties, and that this Consent Decree is fair, 

reasonable, and in the public interest; 

NOW, THEREFORE, before the taking of any testimony, without the adjudication or 

admission of any issue of fact or law except as provided in Section I, and with the consent of the 

Parties, IT IS HEREBY ADJUDGED, ORDERED, AND DECREED as follows: 

I. JURISDICTION AND VENUE 

1. This Court has jurisdiction over the subject matter of this action pursuant to 

28 U.S.C. §§ 1331, 1345, and 1355; Sections 113(b) and 167 of the CAA, 42 U.S.C. §§ 7413(b) 

and 7477; and over the Parties. Venue lies in this District pursuant to Section 113(b) of the 

CAA, 42 U.S.C. § 7413(b); and 28 U.S.C. §§ 1391(b) and (c) and 1395(a), because SDP resides 

and is located in this judicial district and the violations alleged in the Complaint are alleged to 

have occurred in this judicial district. For purposes of this Decree, or any action to enforce this 

Decree, SDP consents to this Court’s jurisdiction over this Decree, over any action to enforce 

this Decree, and over SDP. SDP also consents to venue in this judicial district. 

2. For purposes of this Consent Decree, SDP does not contest that the Complaint 

states claims upon which relief may be granted. 

3. Notice of the commencement of this action has been given to Texas, under 

Sections 113(a)(1) and 113(b) of the CAA, 42 U.S.C. §§ 7413(a)(1) and (b). 

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Case 4:13-cv-02009 Document 2-1 Filed in TXSD on 07/10/13 Page 11 of 121 

II. APPLICABILITY
 

4. The obligations of this Consent Decree apply to and are binding upon the United 

States and upon SDP and any successors, assigns, and other entities or persons otherwise bound 

by law. 

5. SDP shall give written notice of, and shall provide a copy of, the Consent Decree 

to any successors in interest at least sixty (60) days prior to the transfer of ownership or 

operation of any portion of the Covered Facilities. SDP shall notify the United States in 

accordance with the notice provisions in Section XVI (Notice) of any successor in interest at 

least thirty days prior to any such transfer. 

6. If SDP intends to request that the United States agree to a transferee’s assumption 

of any obligations of the Consent Decree, SDP shall condition any transfer, in whole or in part, 

of ownership of, operation of, or other interest (exclusive of any non-controlling, non-operational 

shareholder interest) in the Covered Facilities upon the transferee’s written agreement to execute 

a modification to the Consent Decree that shall make the terms and conditions of the Consent 

Decree applicable to the transferee. 

7. As soon as possible prior to the transfer: (i) SDP shall notify the United States of 

the proposed transfer and of the specific Consent Decree provisions that SDP proposes the 

transferee assume; (ii) SDP shall certify that the transferee is contractually bound to assume the 

obligations and liabilities of this Consent Decree; and (iii) the transferee shall submit to the 

United States a certification that the transferee has the financial and technical ability to assume 

the obligations and liabilities of this Consent Decree and a certification that the transferee is 

contractually bound to assume the obligations and liabilities of this Consent Decree. 

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8. After the submission to the United States of the notice and certification required 

by the previous Paragraph, either: (i) the United States, shall notify SDP that the United States 

does not agree to modify the Consent Decree to make the transferee responsible for complying 

with the terms and conditions of the Consent Decree; or (ii) the United States, SDP, and the 

transferee shall file with the Court a joint motion requesting the Court approve a modification 

substituting the transferee for SDP as the Defendants responsible for complying with the terms 

and conditions of the Consent Decree. 

9. If SDP does not secure the agreement of the United States to a joint motion within 

a reasonable period of time, then SDP and the transferee may file, without the agreement of the 

United States, a motion requesting the Court to approve a modification substituting the transferee 

for SDP as the Defendant responsible for complying with some or all of the terms and conditions 

of the Consent Decree. The United States may file an opposition to the motion. The motion to 

modify shall be granted unless SDP and the transferee: (i) fail to show that the transferee has the 

financial and technical ability to assume the obligations and liabilities of the Consent Decree; 

(ii) fail to show that the modification language effectively transfers the obligations and liabilities 

to the transferee; or (iii) the Court finds other good cause for denying the motion. 

10. Except as provided in Paragraphs 5–9 and Section XI (Force Majeure), SDP shall 

be responsible for ensuring that performance of the work contemplated under this Consent 

Decree is undertaken in accordance with the deadlines and requirements contained in this 

Consent Decree and any attachments hereto. SDP shall provide a copy of all applicable portions 

of this Consent Decree to all officers and employees whose duties might reasonably include 

compliance with any provision of this Decree. No later than the execution of any contract with a 

consulting or contracting firm that is retained to perform work required by this Consent Decree, 

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Case 4:13-cv-02009 Document 2-1 Filed in TXSD on 07/10/13 Page 13 of 121 

SDP shall provide a copy of the applicable provisions of this Consent Decree to each such 

consulting or contracting firm. SDP shall condition any such contract upon performance of the 

work in conformity with the applicable terms of this Consent Decree. No later than thirty (30) 

days after the Date of Lodging of the Consent Decree, SDP also shall provide a copy of the 

applicable provisions of this Consent Decree to each consulting or contracting firm that SDP 

already has retained to perform the work required by this Consent Decree. Copies of the 

applicable provisions of the Consent Decree do not need to be supplied to firms who are retained 

to supply materials or equipment to satisfy requirements of this Consent Decree. 

11. In any action to enforce this Consent Decree, SDP shall not raise as a defense the 

failure by any of its officers, directors, employees, agents, or contractors to take any actions 

necessary to comply with the provisions of this Consent Decree. 

III. DEFINITIONS 

12. Terms used in this Consent Decree that are defined in the CAA or in federal and 

state regulations promulgated pursuant to the CAA, shall have the meaning assigned to them in 

the CAA, or such regulations, unless otherwise provided in this Decree. Whenever the terms set 

forth below are used in this Consent Decree, the following definitions shall apply: 

a. “Ambient Air” or “air” shall mean that portion of the atmosphere, external 

to buildings, to which persons have access. 

b. “Automatic Control System” or “ACS” shall mean a system that utilizes 

programming logic to automate the operation of the instrumentation and systems required in 

Paragraphs 18–23 of this Decree so as to produce the operational results required in 

Paragraphs 53, 56–59. 

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Case 4:13-cv-02009 Document 2-1 Filed in TXSD on 07/10/13 Page 14 of 121 

c. “Available for Operation” shall mean, with respect to a Compressor within 

a Flare Gas Recovery System, that the Compressor is capable of commencing the recovery of 

Potentially Recoverable Gas as soon as practicable but not more than one hour after the Need for 

the Compressor to Operate arises; the period of time, not to exceed one hour, allowed by this 

definition for the startup of a Compressor shall be included in the amount of time that a 

compressor is Available for Operation. 

d. “Barrels per day” or “bpd” shall mean barrels per calendar day. 

e. “Baseload Waste Gas Flow Rate” shall mean, for a particular Regular-Use 

Covered Flare, the daily average flow rate, in scfd, to the Flare, excluding all flows during 

periods of Startup, Shutdown, and Malfunction. The flow rate data period that shall be used to 

determine Baseload Waste Gas Flow Rate is set forth in Subparagraph 30.b.ii. 

f. “BTU/scf” shall mean British Thermal Unit per standard cubic foot. 

g. “Calendar Quarter” shall mean a three-month period ending on March 31, 

June 30, September 30, or December 31. 

h. “Capable of Receiving Sweep, Supplemental, and/or Waste Gas” shall 

mean, for a Flare, that the flow of Sweep, Supplemental, and/or Waste Gas is/are not prevented 

from being directed to the Flare by means of closed valves and/or blinds. 

i. “Center Steam” or “Scen” shall mean steam piped into the center of a Flare 

stack or center of the lower part of the Flare tip where it mixes directly with Vent Gas without 

entraining air. Diagrams illustrating the meaning and location of Center, Lower, and Upper 

Steam are set forth in Appendix 1.1 to this Consent Decree. 

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Case 4:13-cv-02009 Document 2-1 Filed in TXSD on 07/10/13 Page 15 of 121 

j. “Center Steam Volumetric Flow Rate” or “Qs-cen” shall mean the 

volumetric flow rate of Center Steam supplied to a Flare, in scfm, as either measured (if 

applicable) or estimated using best engineering judgment, on a 5-minute block average. 

k. “Center Steam Mass Flow Rate” or “ṁs-cen” shall mean the mass flow rate 

of Center Steam supplied to a Flare, in pounds per hour, as either measured (if applicable) or 

estimated using best engineering judgment, on a 5-minute block average using Equation 2 in 

Appendix 1.2. 

l. “Combustion Efficiency” or “CE” shall mean a Flare’s efficiency in 

converting the organic carbon compounds found in Vent Gas to carbon dioxide. Combustion 

Efficiency shall be determined as set forth in Equation 1 in Appendix 1.2. 

m. “Combustion Efficiency Multipliers” or “CE Multipliers” shall mean 

empirically derived factors that are used as multipliers of the Net Heating Value of the Vent Gas 

at its Lower Flammability Limit to ensure an acceptable Combustion Efficiency. The CE 

Multipliers are set forth in Table 2 of Appendix 1.3 of this Consent Decree. 

n. “Combustion Zone” shall mean the area of the Flare flame where the 

combustion of Combustion Zone Gas occurs. 

o. “Combustion Zone Gas” shall mean the mixture of all gases and steam 

found after the Flare tip. This gas includes all Vent Gas, all Pilot Gas, and all Total Steam. 

p. “Compressor” shall mean, with respect to a Flare Gas Recovery System, a 

mechanical device designed and installed to recover gas from a flare header. Types of Flare Gas 

Recovery System compressors include reciprocating compressors, centrifugal compressors, 

liquid ring compressors and liquid jet ejectors. 

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q. “Consent Decree” or “Decree” shall mean this Consent Decree, including 

any and all appendices attached hereto. 

r. “Covered Facilities” shall mean the SDP Chemical Plant and the SDP 

Refinery. 

s.	 “Covered Flare” shall mean each of the following Flares: 

At SDP Chemical Plant At SDP Refinery 

A&S CCU 

HIPA Coker 

Olefins II East Property 

Olefins III Ethylene (aka Girbotol) 

Olefins Ground North Property 

South Property 

West Property 

t. “Date of Lodging of this Consent Decree” or “Date of Lodging” or 

“DOL” shall mean the date that this Consent Decree is filed for lodging, pending solicitation of 

public comment, with the Clerk of the Court for the United States District Court for the Southern 

District of Texas. 

u. “Date of Entry of this Consent Decree” or “Date of Entry” or “DOE” shall 

mean the Effective Date of this Consent Decree. 

v. “Discontinuous Wake Dominated Flow” shall mean gas flow exiting a 

Flare tip that is identified visually by: 

(i)	 The presence of a flame that is: (1) immediately adjacent to the 

exterior of the Flare tip body; and (2) below the exit plane of the 

Flare tip; and 

(ii) A discontinuous flame, such that pockets of flame are detached 

from the portion of the flame that is immediately adjacent to the 

exterior of the Flare tip body. Representations of Discontinuous 

Wake Dominated Flow are set forth in Appendix 1.12. 

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w. “Duplicate Spare Compressor” shall mean, with respect to a Flare Gas 

Recovery System, an installed compressor, designed to be identical or functionally equivalent to 

the other compressor(s) of the FGRS. In order to qualify as a “Duplicate Spare Compressor,” the 

compressor must be functionally interchangeable with the other FGRS compressor(s) such that 

the Operating Design Capacity of the FGRS is Available for Operation while any one 

compressor of the FGRS is out of service. The capacity of a Duplicate Spare Compressor 

depends upon the number of compressors installed to meet the Operating Design Capacity of the 

FGRS. For example, if one compressor is installed to provide an Operating Design Capacity of 

270 kscfh, the Duplicate Spare Compressor shall have a capacity of 270 kscfh; if, instead, three, 

90 kscfh compressors are installed, the Duplicate Spare Compressor shall have a capacity of 90 

kscfh. 

x. “Effective Date” shall have the definition set forth in Section XVII 

(Effective Date) of this Consent Decree. 

y. “Elevated Flare” shall mean a Flare that supports combustion at a tip that 

is situated at the upper end of a vertical conveyance (e.g., pipe, duct); the combustion zone is 

elevated in order to separate the heat generated by combustion from people, equipment, or 

structures at grade level. 

z. “EPA” shall mean the United States Environmental Protection Agency 

and any of its successor departments or agencies. 

aa. “Exit Velocity” shall mean the velocity (“v”), in feet per second, of the 

Vent Gas and Center Steam as they exit the flare tip. Exit Velocity shall be calculated by adding 

together the Vent Gas Volumetric Flow Rate and the Center Steam Volumetric Flow Rate, based 

on standard conditions, and dividing by the Unobstructed Cross Sectional Area of the Flare Tip. 

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bb. “External Utility Loss” shall mean a loss in the supply of electrical power 

or other third-party utility to a Covered Facility that is caused by events occurring outside the 

boundaries of a Covered Facility, excluding utility losses due to an interruptible utility service 

agreement. 

cc. “First Updated Waste Gas Minimization Plan” or “First Updated WGMP” 

shall mean the document submitted pursuant to Paragraph 31 as the first update to the Initial 

WGMP. 

dd. “Flare” shall mean a combustion device that uses an uncontrolled volume 

of Ambient Air to burn gases. 

ee. “Flare Gas Recovery System” or “FGRS” shall mean a system of one or 

more compressors, piping, and associated water seal, rupture disk, or similar device used to 

divert gas from a Flare and direct the gas to a fuel gas system, to a combustion device other than 

the Flare, or to a product, co-product, by-product, or raw material recovery system. 

ff. “Fuel Gas” shall have the definition set forth in 40 C.F.R. § 60.101a. 

gg. “Ground Flare” shall mean a Flare or array of Flare tips that supports 

combustion at or near grade level and uses some form of shielding or barrier to separate the heat 

generated by combustion from people, equipment, and structures at grade level. Ground Flares 

include Flares that are partially enclosed. 

hh. “Initial Waste Gas Minimization Plan” or “Initial WGMP” shall mean the 

document submitted pursuant to Paragraph 30. 

ii. “In Operation” or “Being In Operation” or “Operating,” with respect to a 

Flare, shall mean any and all times that any gas (e.g., Waste, Vent, Purge, Pilot,) is or may be 

vented to a Flare. A Flare that is In Operation is Capable of Receiving Sweep, Supplemental, 

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and/or Waste Gas unless all Sweep, Supplemental, and Waste Gas flow is prevented by means of 

closed valves and/or blinds. 

jj. “KSCFH” or “kscfh” shall mean thousand standard cubic feet per hour. 

kk. “Lower Flammability Limit” or “LFL” shall mean the lowest volumetric 

concentration of a combustible gas in air that, at a given temperature and pressure, will still 

combust. 

ll. “Lower Flammability Limit of Vent Gas” or “LFLvg” shall mean the 

weighted average of the LFLs of each of the individual compounds in Vent Gas, weighted by 

their volume fraction in the Vent Gas. LFLvg is represented by and shall be calculated according 

to Equation 1 in Appendix 1.3 of this Consent Decree. 

mm. “Lower Heating Value” or “LHV” shall mean the theoretical total quantity 

of heat liberated by the complete combustion of a unit volume or weight of a fuel initially at 25 

degrees Centigrade and 760 mmHg, assuming that the produced water is vaporized and all 

combustion products remain at, or are returned to, 25 degrees Centigrade; however, the standard 

for determining the volume corresponding to one mole is 20 degrees Centigrade. 

nn. “Lower Steam” shall mean steam piped to an exterior annular ring near the 

lower part of a Flare tip, which entrains Ambient Air which flows through tubes to the Flare tip, 

and ultimately exits the tubes at the top of the Flare tip. Diagrams illustrating the meaning and 

location of Center, Lower, and Upper Steam are set forth in Appendix 1.1 to this Consent 

Decree. 

oo. “Malfunction” shall mean any sudden, infrequent, and not reasonably 

preventable failure of air pollution control equipment, process equipment, or a process to operate 

in a normal or usual manner. Failures that are caused in part by poor maintenance or careless 

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operation are not Malfunctions. In any action under this Consent Decree involving this 

definition, SDP shall have the burden of proving a Malfunction and, in interpreting this 

definition, the ten requirements for a “malfunction” set forth in Section II (“Affirmative Defenses 

for Malfunctions”) of EPA’s Policy on Excess Emissions during Malfunctions, Startup, and 

Shutdown shall apply. This Policy is attached as Appendix 1.4. 

pp. Momentum Flux Ratio” or “MFR” shall mean the ratio of the Vent Gas 

and Center Steam momentum flux to the wind momentum flux, where momentum flux is the 

momentum per unit area, per unit time. MFR characterizes the degree to which the Ambient Air 

affects the trajectory of the Vent Gas and Center Steam just as it exits the Flare tip. MFR is 

represented by Equation 1 in Appendix 1.5 and shall be calculated in accordance with the 

equations, conversion factors, MFR constants, MFR measured variables, and MFR calculated 

variables set forth in Appendix 1.5. 

qq. “Need for a Compressor to Operate” shall mean: 

i. For a situation in which no Compressor within the FGRS is 

recovering gas: When a Potentially Recoverable Gas flow rate 

(determined on a five-minute block average) to the Covered 

Flare(s) serviced by the Flare Gas Recovery System exists; or 

ii. For a situation in which one or more Compressors within the 

FGRS already are recovering gas: When the Potentially 

Recoverable Gas flow rate (determined on a five-minute block 

average) exceeds the capacity of the operating Compressor(s). 

rr. “Net Heating Value” shall mean Lower Heating Value. 

ss. “Net Heating Value of Combustion Zone Gas” or “NHVcz” shall mean the 

Lower Heating Value, in BTU/scf, of the Combustion Zone Gas in a Flare. NHVcz is represented 

by Equation 5.a or 5.b in Appendix 1.3 to this Consent Decree and shall be calculated in 

accordance with Equations 5–8 of Appendix 1.3. 

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tt. “Net Heating Value of Combustion Zone Gas Limit” or “NHVcz-limit” shall 

mean the minimum Net Heating Value that the Combustion Zone Gas must have to ensure an 

acceptable Combustion Efficiency. 

uu. “Net Heating Value of Hydrogen as Adjusted” or “NHVH2-adj” shall mean 

1212 BTU/scf. NHVH2-adj represents an adjustment to hydrogen’s actual Net Heating Value for 

use, consistent with Step 3 of Appendix 1.3, in the calculation of the NHVvg. 

vv. “Net Heating Value of Vent Gas” or “NHVvg” shall mean the Lower 

Heating Value, in BTU/scf, of the Vent Gas directed to a Flare. NHVvg is calculated as set forth 

in Equation 2 of Appendix 1.3. 

ww. “Net Heating Value of Vent Gas at its Lower Flammability Limit” or 

“NHVvg-LFL” shall mean the Lower Heating Value, in BTU/scf, of the Vent Gas at its LFL. 

NHVvg-LFL is represented by and shall be calculated in accordance with Equation 3 of 

Appendix 1.3 of this Consent Decree. 

xx. “Olefins,” for purposes of this Consent Decree, shall mean the following 

compounds: 

Ethene (a/k/a ethylene) 

Propene (a/k/a propylene) 

Acetylene 

But-1-ene (a/k/a butene, alpha-butylene) 

Z-but-2-ene (a/k/a beta-butylene, cis-butene) 

E-but-2-ene (a/k/a beta-butylene, trans-butene) 

2-methylpropene (a/k/a iso-butylene, iso-butene) 

1,3 butadiene 

yy. “Olefins FGRS” shall mean one or more Flare Gas Recovery Systems 

designed and operated to recover gas that otherwise would be directed to the Olefins Flares. 

zz. “Olefins Flares” shall mean each of the following Covered Flares: the 

Olefins II Flare, Olefins III Flare, and the Olefins Ground Flare. 

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aaa. “Operating Design Capacity” shall mean, with respect to a Flare Gas 

Recovery System, the sum of the capacities, in kscfh, of the installed flare gas recovery 

Compressors, excluding the capacity of the one installed Duplicate Spare Compressor. 

bbb. “Pilot Gas” shall mean all gas introduced through the pilot tip(s) of a 

Flare to maintain a flame. 

ccc. “Portable Flare” shall mean a Flare that is not permanently installed that 

receives Waste Gas that has been redirected to it from a Covered Flare for periods that are 

anticipated to be 504 hours or less on a rolling 1095-day period. 

ddd. “Potentially Recoverable Gas” shall mean the Sweep Gas, Supplemental 

Gas, and/or Waste Gas (including hydrogen, nitrogen, oxygen, carbon dioxide, carbon 

monoxide, and/or water) directed to a Covered Flare’s or group of Covered Flares’ FGRS. 

Hydrogen produced by the Pressure Swing Absorption (“PSA”) units at the Covered Facilities 

and introduced between a Covered Flare’s water seal and a Covered Flare’s tip is not Potentially 

Recoverable Gas. 

eee. “Prevention Measure” shall mean an instrument, device, piece of 

equipment, system, process change, physical change to process equipment, procedure, or 

program to minimize or eliminate flaring. 

fff. “Purge Gas” shall mean the minimum amount of gas introduced between a 

Flare header’s water seal and the Flare tip to prevent oxygen infiltration (backflow) into the Flare 

tip. For a Flare with no water seal, the function of Purge Gas is performed by Sweep Gas, and 

therefore, by definition, such a Flare has no Purge Gas. 

ggg. “Regular-Use Flare” shall mean any flare that is not a Temporary-Use or 

Portable Flare. 

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Case 4:13-cv-02009 Document 2-1 Filed in TXSD on 07/10/13 Page 23 of 121 

hhh. “Regular-Use Covered Flare” shall mean each of the following Covered 

Flares: 

At SDP Chemical Plant At SDP Refinery 

HIPA Coker 

Olefins II East Property 

Olefins III Ethylene (aka Girbotol) 

Olefins Ground North Property 

West Property 

iii. “Reportable Flaring Incident” shall mean, for each of the following time 

periods, when any one of the following quantities is flared within a 24-hour period at the 

Covered Facilities: 

From the submission of the Initial WGMP 

until the submission of First Updated WGMP 

From the submission of the First 

Updated WGMP through all 

times thereafter 

≥ 500 lb SO2 (Refinery Covered Flares Only) ≥ 500,000 scf Waste Gas (All 

Covered Flares) 

≥ 500 lb SO2 (Refinery Covered 

Flares Only) 

Events that have the same root cause(s) that last more than 24 hours shall be considered a single 

incident. For purposes of calculating whether the triggering level of SO2 emissions has been 

met, when flaring occurs at more than one Covered Flare, the quantity of SO2 from all Covered 

Flares involved shall be added together unless the root cause(s) of the flaring at the respective 

Covered Flares is(are) not related to each other. For purposes of calculating whether the 

triggering level of Waste Gas flow has been met, the following flows may be excluded: (i) the 

pro-rated Baseload Waste Gas Flow Rate (pro-rated on the basis of the duration of the 

Reportable Flaring Incident); and (ii) if SDP has instrumentation capable of calculating the 

volumetric flow rate of hydrogen, nitrogen, oxygen, carbon monoxide, carbon dioxide, and/or 

water (steam) in the Waste Gas, the contribution of all measured flows of any of these 

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Case 4:13-cv-02009 Document 2-1 Filed in TXSD on 07/10/13 Page 24 of 121 

elements/compounds. When flaring occurs at more than one Covered Flare, the volume of 

non-excluded Waste Gas flow at all Covered Flares involved shall be added together unless the 

root cause(s) of the flaring at the respective Covered Flares is (are) not related to each other. 

jjj. “SCFD” or “scfd” shall mean standard cubic feet per day. 

kkk. “SCFH” or “scfh” shall mean standard cubic feet per hour. 

lll. “SCFM” or “scfm” shall mean standard cubic feet per minute. 

mmm. “SDP” shall mean Shell Oil Company, Deer Park Refining Limited 

Partnership, and Shell Chemical LP. 

nnn. “SDP Chemical Plant” shall mean the chemical plant owned and operated 

by Shell Chemical LP located at 5900 Highway 225 East, Deer Park, TX 77536. 

ooo. “SDP Chemical Plant Covered Flare” shall mean each of the following 

Covered Flares: 

A&S 

HIPA 

Olefins II 

Olefins III 

Olefins Ground 

ppp. “SDP Refinery” shall mean petroleum refinery owned by Deer Park 

Refining Limited Partnership and operated by Shell Oil Company and located at 5900 Highway 

225 East, Deer Park, TX 77536. 

qqq. “SDP Refinery Covered Flare” shall mean each of the following Covered 

Flares: 

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Case 4:13-cv-02009 Document 2-1 Filed in TXSD on 07/10/13 Page 25 of 121 

CCU
 

Coker
 

East Property
 

Ethylene (aka Girbotol)
 

North Property
 

South Property
 

West Property
 

rrr. “Shell’s PRI Consent Decree” shall mean the Petroleum Refinery 

Initiative Consent Decree, as amended and revised, entered in an action styled United States, et 

al. v. Deer Park Refining Limited Partnership, CA No. H-01-0978 (S.D. Texas). 

sss. “Shutdown” shall mean the cessation of operation for any purpose. 

ttt. “Smoke Emissions” shall have the definition set forth in Section 3.5 of 

Method 22 of 40 C.F.R. Part 60, Appendix A. Smoke Emissions may be documented either by a 

person certified pursuant to Method 22 or by a video camera. 

uuu. “Standard Conditions” shall mean a temperature of 68 degrees Fahrenheit 

and a pressure of 1 atmosphere. Unless otherwise expressly set forth in this Consent Decree or 

an Appendix, Standard Conditions shall apply. 

vvv. “Startup” shall mean the setting in operation for any purpose. 

www. “Steam-Assisted Flare” shall mean a Flare that utilizes steam piped to a 

Flare tip to assist in combustion. 

xxx. “Supplemental Gas” shall mean all gas introduced to a Flare to comply 

with: (1) the net heating value requirements of 40 C.F.R. § 60.18(b), 40 C.F.R. § 63.11(b), and/or 

Paragraph 56 of this Consent Decree; and/or (2) the requirements of Paragraphs 57 and/or 58. 

yyy. “S/VGmass” or “Total-Steam-Mass-Flow-Rate-to-Vent-Gas-Mass-FlowRate Ratio” shall mean the ratio of the Total Steam Mass Flow Rate to the Vent Gas Mass Flow 

Rate. 

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Case 4:13-cv-02009 Document 2-1 Filed in TXSD on 07/10/13 Page 26 of 121 

zzz.	 “Sweep Gas” shall mean: 

i.	 For a Flare with a Water Seal: The minimum amount of gas 

introduced into a Flare header in order to: (a) prevent oxygen 

buildup, corrosion, and/or freezing in the Flare header; and 

(b) maintain a safe flow of gas through the Flare header, including 

a higher flow during hot taps. Sweep Gas in these Flares is 

introduced prior to and is intended to be recovered by the Flare 

Gas Recovery System; and 

ii.	 For a Flare without a Water Seal: The minimum amount of gas 

introduced into a Flare header in order to: (a) prevent oxygen 

buildup, corrosion, and/or freezing in the Flare header; 

(b) maintain a safe flow of gas through the Flare header, including 

a higher flow during hot taps; and (c) prevent oxygen infiltration 

(backflow) into the Flare tip. 

aaaa. “Temporary-Use Flare” shall mean a permanently installed Flare that 

receives Waste Gas that has been redirected to it from another flare for periods that are 

anticipated to be 504 hours or less on a rolling 1095-day average period. 

bbbb. “Temporary-Use Covered Flare” shall mean each of the following 

Covered Flares: A&S, South Property, and CCU. 

cccc. “Total Capacity” shall mean, with respect to a Flare Gas Recovery 

System, the sum of the capacities, in kscfh, of the installed flare gas recovery Compressors, 

including the capacity of the one installed Duplicate Spare Compressor. 

dddd. “Total Steam” or “S” shall mean the total of all steam that intentionally is 

introduced into a Steam-Assisted Flare to assist in combustion. Total Steam includes, but is not 

limited to, Lower Steam, Center Steam, and Upper Steam. 

eeee. “Total Steam Mass Flow Rate” or “ṁs” shall mean the mass flow rate of 

Total Steam supplied to a Flare, in pounds per hour as calculated on a 5-minute block average. 

Total Steam Mass Flow Rate shall be calculated as set forth in Equation 3 of Appendix 1.2. 

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Case 4:13-cv-02009 Document 2-1 Filed in TXSD on 07/10/13 Page 27 of 121 

ffff. “Total-Steam-Mass-Flow-Rate-to-Vent-Gas-Mass-Flow-Rate Ratio” or 

“S/VGmass” shall mean the ratio of the Total Steam Mass Flow Rate to the Vent Gas Mass Flow 

Rate. 

gggg. “Unobstructed Cross Sectional Area of the Flare Tip” or “Atip-unob” shall 

mean the open, unobstructed area of a Flare tip through which Vent Gas and Center Steam pass. 

Diagrams of four common flare types are set forth in Appendix 1.6 together with the equations 

for calculating the Atip-unob of these four types. 

hhhh. “Upper Steam,” sometimes called Ring Steam, shall mean steam piped to 

nozzles located on the exterior perimeter of the upper end of a Flare tip. Diagrams illustrating 

the meaning and location of Center, Lower, and Upper Steam are set forth in Appendix 1.1 to 

this Consent Decree. 

iiii. “Velocity of the Wind” or “Wind Speed” or “vwind” shall mean the velocity 

of the Ambient Air, in ft/s on a five-minute block average, measured at the Meteorological 

Station required pursuant to Paragraph 23 of this Consent Decree. 

jjjj. “Vent Gas” shall mean the mixture of all gases found just prior to the 

Flare tip. This gas includes all Waste Gas, Sweep Gas, Purge Gas, and Supplemental Gas, but 

does not include Pilot Gas, Total Steam, or Assist Air. 

kkkk. “Vent Gas Volumetric Flow Rate” or “Qvg” shall mean the volumetric 

flow rate of Vent Gas directed to a Covered Flare, in wet scfm, on a 5-minute block average 

basis. 

llll. “Vent Gas Mass Flow Rate” or “ṁvg” shall mean the mass flow rate of 

Vent Gas directed to a Covered Flare, in pounds per hour on a 5-minute block average. Vent 

Gas Mass Flow Rate shall be calculated as set forth in Equation 4 of Appendix 1.2. 

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Case 4:13-cv-02009 Document 2-1 Filed in TXSD on 07/10/13 Page 28 of 121 

mmmm. “Vent Gas Molecular Weight” or “MWvg” shall mean the 

Molecular Weight, in pounds per pound-mole, of the Vent Gas, on a 5-minute block average. 

nnnn. “Visible Emissions” shall mean five minutes or more of Smoke Emissions 

during any two consecutive hours. For purposes of this Consent Decree, Visible Emissions may 

be determined by a person certified pursuant to Method 22 or documented by a video camera. 

oooo. “VOC” or “Volatile Organic Compounds” shall have the definition set 

forth in 40 C.F.R. § 51.100(s). 

pppp. “VOC Vent Gas Concentration” shall mean the volumetric concentration 

of VOCs in the Vent Gas and shall be calculated as set forth in Equation 15 of Appendix 1.3. 

qqqq. “Waste Gas” shall mean the mixture of all gases from facility operations 

that is directed to a flare for the purpose of disposing of the gas. “Waste Gas” does not include 

gas introduced to a flare exclusively to make it operate safely and as intended; therefore, “Waste 

Gas” does not include Pilot Gas, Total Steam, Assist Air, or the minimum amount of Sweep Gas 

and Purge Gas that is necessary to perform the functions of Sweep Gas and Purge Gas. “Waste 

Gas” also does not include the minimum amount of gas introduced to a flare to comply with 

regulatory and/or enforceable permit requirements and/or the requirements of Paragraphs 56, 57, 

or 58; therefore, “Waste Gas” does not include Supplemental Gas. Depending upon the 

instrumentation that monitors Waste Gas, certain compounds (hydrogen, nitrogen, oxygen, 

carbon dioxide, carbon monoxide, and/or water (steam)) that are directed to a Flare for the 

purpose of disposing of these compounds may be excluded from calculations relating to Waste 

Gas flow. In Section V of this Consent Decree, the circumstances in which such exclusions are 

permitted are specifically identified. Appendix 1.7 to this Consent Decree depicts the meaning 

of “Waste Gas,” together with its relation to other gases associated with Flares. 

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Case 4:13-cv-02009 Document 2-1 Filed in TXSD on 07/10/13 Page 29 of 121 

IV. CIVIL PENALTY
 

13. By no later than 30 days after the Effective Date of this Consent Decree, SDP 

shall pay the sum of Two Million, Six-Hundred Thousand Dollars ($2,600,000) as a civil 

penalty. SDP shall pay the civil penalty by FedWire Electronic Funds Transfer (“EFT”) to the 

U.S. Department of Justice in accordance with written instructions to be provided to SDP, 

following lodging of the Consent Decree, by the Financial Litigation Unit of the U.S. Attorney=s 

Office for the Southern District of Texas, 1000 Louisiana St., Suite 2300, Houston, TX 77002. 

At the time of payment, SDP shall send a copy of the EFT authorization form, the EFT 

transaction record, and a transmittal letter: (i) to the United States in the manner set forth in 

Section XVI of this Decree (Notices); (ii) by email to acctsreceivable.CINWD@epa.gov; and 

(iii) by mail to: 

EPA Cincinnati Finance Office 

26 Martin Luther King Drive 

Cincinnati, Ohio 45268 

The transmittal letter shall state that the payment is for the civil penalty owed pursuant to the 

Consent Decree in United States v. Shell Oil Company, et al., and shall reference the civil action 

number, USAO File Number 2012VO1637, and DOJ case number 90-5-2-1-09388/1. 

14. If any portion of the civil penalty due to the United States is not paid when due, 

SDP shall pay interest on the amount past due, accruing from the Effective Date through the date 

of payment, at the rate specified in 28 U.S.C. § 1961. Interest payment under this Paragraph 

shall be in addition to any stipulated penalty due. 

15. SDP shall not deduct any penalties paid under this Decree pursuant to this Section 

or Section X (Stipulated Penalties) in calculating its federal income tax. 

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Case 4:13-cv-02009 Document 2-1 Filed in TXSD on 07/10/13 Page 30 of 121 

V. COMPLIANCE REQUIREMENTS
 

A. Instrumentation and Monitoring Systems 

16. Flare Data and Monitoring Systems and Protocol Report (“Flare Data and 

Monitoring Systems and Protocol Report”). For the Covered Flares, by no later than the dates 

set forth in Column B of Appendix 2.1, SDP shall submit a report, consistent with the 

requirements in Appendix 1.8, to EPA that includes the following: 

a. The information, diagrams, and drawings specified in Paragraphs 1–7 of 

Appendix 1.8; 

b. A detailed description of each instrument and piece of monitoring 

equipment, including the specific model and manufacturer, that SDP has 

installed or will install in compliance with Paragraphs 18–23 of this 

Consent Decree (Paragraphs 8–9 of Appendix 1.8); 

c. A narrative description of the monitoring methods and calculations that 

SDP shall use to comply with the requirements of Paragraphs 56–58 

(Paragraph 10 of Appendix 1.8); and 

d. The identification of the calibration gases to be used to comply with 

Subparagraph V.B.1 of Appendix 1.10 (Paragraph 11 of Appendix 1.8). 

For any H2S CEMS required pursuant to 40 C.F.R. Part 60, Subpart J or Subpart Ja, this report 

shall satisfy the notification requirements of 40 C.F.R. § 60.7(a)(5). 

17. Installation and Operation of Monitoring Systems. 

a. Regular-Use Covered Flares. By no later than the dates set forth in 

Column C of Appendix 2.1, for each Regular-Use Covered Flare, SDP shall have completed the 

installation and commenced the operation of the instrumentation, controls, and monitoring 

systems set forth in Paragraphs 18–24. 

b. Temporary-Use Covered Flares. Prior to directing any Vent Gas to any 

Temporary-Use Covered Flare, SDP shall have completed the installation of the instrumentation, 

controls, and monitoring systems set forth in Paragraphs 18–24. SDP shall operate the 

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Case 4:13-cv-02009 Document 2-1 Filed in TXSD on 07/10/13 Page 31 of 121 

instrumentation, controls, and monitoring systems for each Temporary-Use Covered Flare at all 

times that the Flare is Capable of Receiving Sweep, Supplemental, and/or Waste Gas. During 

periods when a Temporary-Use Covered Flare is not Capable of Receiving Sweep, 

Supplemental, and/or Waste Gas, the instrumentation, controls, and monitoring systems in 

Paragraphs 18–24 may be removed and the continuous operation, maintenance, and calibration 

of those instruments, controls and monitoring systems is not required; provided however, that 

prior to the Startup of any Temporary-Use Covered Flare, SDP shall take all necessary steps to 

ensure that the instruments, controls, and monitoring systems are calibrated properly and are 

capable of continuous operation for the full duration of the use of the Temporary-Use Covered 

Flare. 

18.	 Vent Gas Flow Monitoring System. This system shall: 

a.	 Continuously measure and calculate the total flow, in scfm and pounds per 

hour, of all Vent Gas; 

b.	 Continuously analyze pressure and temperature at each point of Vent Gas 

flow measurement; and 

c.	 Have retractable or removable sensors at each point of Vent Gas flow 

measurement to ensure that the Vent Gas Flow Monitoring System is 

maintainable online. 

19. Vent Gas Average Molecular Weight Analyzer. This instrument or system shall 

continuously analyze the average molecular weight of all Vent Gas. This analysis may be 

performed by an instrument that also serves as part of a Vent Gas Flow Monitoring System. 

20.	 Total Steam Flow Monitoring System. This system shall: 

a.	 Continuously measure and calculate the flow, in scfm and pounds per 

hour, of the Total Steam to each Covered Flare; and 

b.	 Continuously analyze the pressure and temperature of steam at a 

representative point of steam flow measurement. 

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Case 4:13-cv-02009 Document 2-1 Filed in TXSD on 07/10/13 Page 32 of 121 

21. Steam Control Equipment. This equipment, including, as necessary, main and 

trim control valves and piping, shall enable SDP to control steam flow in a manner sufficient to 

ensure compliance with this Decree. 

22. Gas Chromatograph (“GC”) or Net Heating Value Analyzer. Each Regular-Use 

Covered Flare shall be equipped with a GC. Each Temporary-Use Covered Flare shall be 

equipped with either a GC or a Net Heating Value Analyzer. The GCs and, to the extent used, 

Net Heating Value Analyzers, shall meet the following requirements: 

a.	 Gas Chromatograph. This instrument shall be capable of speciating the 

Vent Gas constituents set forth in Appendix 1.9.on a mole percent 

(“mol/mol%”) basis. The sample extraction point of the Gas 

Chromatograph may be located upstream of the introduction of 

Supplemental and/or Sweep and/or Purge Gas if the composition and flow 

rate of any such Supplemental and/or Sweep and/or Purge Gas is a known 

constant and if this constant then is used in the calculation of the volume 

percent of all gas constituents of the Vent Gas. 

b.	 Net Heating Value Analyzer. This instrument shall measure the Net 

Heating Value of the Vent Gas in BTU/scf. The sample extraction point 

of the Net Heating Value Analyzer may be located upstream of the 

introduction of Supplemental and/or Sweep and/or Purge Gas if the 

composition and flow rate of any such Supplemental and/or Sweep and/or 

Purge Gas is a known constant and if this constant then is used in the 

calculation of the Net Heating Value of the Vent Gas. 

23. Meteorological Station or “Met Station” (one Met Station can to be used for both 

Covered Facilities; not one for each Covered Facility and not one for each Covered Flare). This 

station shall include meteorological data instruments capable of measuring wind speed. The 

station shall be placed at a location where wind is representative of conditions at the Regular-Use 

Covered Flare with the largest estimated volume of Waste Gas after Waste Gas minimization is 

complete. The Meteorological Station shall be located as high as reasonably practicable but does 

not have to be as high as the Regular-Use Covered Flare that its location is based on. 

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24. Video Camera. This instrument shall record, in digital format, the flame of 

(including any resulting from Discontinuous Wake Dominated Flow), and any Smoke Emissions 

from, the Regular-Use Covered Flares. 

25. Instrumentation and Monitoring Systems: Optional Equipment for any Covered 

Flare. At its option, SDP may elect to install (if not already installed) an instrument to 

continuously measure and calculate flow, in scfm and pounds per hour, of all Pilot Gas to a 

Covered Flare. SDP may utilize the data generated by this instrument as part of the calculation 

of the Net Heating Value of the Combustion Zone Gas. 

26. Instrumentation and Monitoring Systems: Specifications. The instrumentation 

and monitoring systems identified in Paragraphs 18–20 and 22–23 shall meet or exceed the 

specifications set forth in Appendix 1.10. 

27. Instrumentation and Monitoring Systems: Recording and Averaging Times. The 

instrumentation and monitoring systems identified in Paragraphs 18–20 and 22–24 shall be able 

to produce and record data measurements and calculations for each parameter at the following 

time intervals. 

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Case 4:13-cv-02009 Document 2-1 Filed in TXSD on 07/10/13 Page 34 of 121 

Instrumentation and Monitoring System Recording and Averaging Times 

Vent Gas Flow; 

Vent Gas Average Molecular Weight; 

Total Steam Flow; 

Pilot Gas Flow (if installed) 

Measure continuously and record 5 

minute block averages 

Gas Chromatograph Measure no less than once every 15 

minutes and record that value 

Net Heating Value Analyzer Measure continuously and record 5 

minute block averages 

Wind Speed Measure continuously and record 5 

minute block averages 

Video Camera Record at a rate of no less than 4 

frames per minute 

Nothing in this Paragraph is intended to prohibit SDP from setting up process control logic that 

uses different averaging times from those in this table provided that the recording and averaging 

times in this table are available and used for determining compliance with this Consent Decree. 

28. Instrumentation and Monitoring Systems: Operation and Maintenance. SDP 

shall operate each of the instruments and monitoring systems required in Paragraphs 18–20 and 

22–24 on a continuous basis when the Covered Flare that the instrument and/or monitoring 

system is associated with is In Operation and Capable of Receiving Sweep, Supplemental, and/or 

Waste Gas, except for the following periods: 

a.	 Malfunction of an instrument and/or monitoring system; 

b.	 Maintenance following instrument and/or monitoring system Malfunction; 

c.	 Scheduled maintenance of an instrument and/or monitoring system in 

accordance with the manufacturer’s recommended schedule; and/or 

d. Quality Assurance/Quality Control activities. 

In no event, however, shall the excepted activities in Subparagraph 28.a–28.d for any instrument 

monitoring a Regular-Use Covered Flare exceed 110 hours in any calendar quarter nor shall the 

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Case 4:13-cv-02009 Document 2-1 Filed in TXSD on 07/10/13 Page 35 of 121 

excepted activities in Subparagraph 28.a–28.d for any instrument monitoring a Temporary-Use 

Covered Flare exceed 5% of the time that the Temporary-Use Covered Flare is In Operation and 

Capable of Receiving Sweep, Supplemental, and/or Waste Gas during an uninterrupted time 

period. The calculation of instrument downtime shall be made in accordance with 40 C.F.R. 

§ 60.13(h)(2) and Paragraph VI of Appendix 1.10. If the excepted activities in 

Subparagraphs 28.a–28.d for any instrument exceed their allowable amount, EPA shall be 

entitled to seek stipulated penalties as set forth in Subparagraph 93.e or 93.f (as applicable) of 

this Consent Decree and SDP shall be entitled to assert that the period of instrumentation and 

monitoring system downtime was justified under the circumstances. Nothing in this Paragraph is 

intended to prevent SDP from claiming a force majeure defense to any period of instrumentation 

and/or monitoring system downtime. Nothing in this Paragraph supersedes or replaces the 

monitoring requirements, including operation, maintenance, and quality assurance/quality 

control requirements of 40 C.F.R. Part 60, Subparts J and Ja at such time as those requirements 

become applicable pursuant to Paragraph 64. All such requirements shall apply in accordance 

with the terms set forth in Subparts J and Ja. 

B.	 Determining Whether a Covered Flare that has a Water Seal is Not Receiving 

Potentially Recoverable Gas Flow 

29. For a Covered Flare that has a water seal, if all of the following conditions are 

met, then the Covered Flare is not receiving Potentially Recoverable Gas flow: 

a.	 For the water seal drum associated with the respective Covered Flare, the 

pressure difference between the inlet pressure and the outlet pressure is 

less than the water seal pressure as set by the static head of water between 

the opening of the dip tube in the drum and the level-setting weir in the 

drum; 

b.	 For the water seal drum associated with the respective Covered Flare, the 

water level in the drum is at the level of the weir; and 

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Case 4:13-cv-02009 Document 2-1 Filed in TXSD on 07/10/13 Page 36 of 121 

c.	 Downstream of the seal drum, there is no flow of Supplemental Gas 

directed to the Covered Flare. 

C.	 Waste Gas Minimization 

30. Initial Waste Gas Minimization Plan (“Initial WGMP”). By no later than the 

dates set forth in Column D of Appendix 2.1, for each Regular-Use Covered Flare, SDP shall 

submit to EPA an Initial Waste Gas Minimization Plan that discusses and evaluates flaring 

Prevention Measures both Facility-wide and on a Flare-specific basis. The Initial WGMP 

submitted for the HIPA Flare shall include a discussion and evaluation of flaring Prevention 

Measures that were implemented for gas that was directed to the A&S Flare before that gas was 

rerouted to the HIPA Flare. The Facility-wide evaluation shall include one evaluation for the 

SDP Refinery and a separate evaluation for the SDP Chemical Plant; provided however, that 

interconnections between the two Covered Facilities may be evaluated on a consolidated basis. 

The Initial WGMP shall include but not be limited to: 

a. Updates. SDP shall submit updates, if and as necessary, to the 

information, diagrams, and drawings provided in the Flare Data and Monitoring Systems and 

Protocol Report required under Paragraph 16. 

b. Waste Gas Characterization and Mapping. SDP shall undertake to 

characterize the Waste Gas being disposed of at each Regular-Use Covered Flare and determine 

its source as follows: 

i.	 Volumetric (in scfm) and mass (in pounds) flow rate. SDP shall 

identify the volumetric flow of Waste Gas, in scfm on a 30-day 

rolling average, and the mass flow rate, in pounds per hour on a 

30-day rolling average, vented to each Regular-Use Covered Flare 

for the one-year period of time prior to 31 days before the 

submission of the Initial WGMP. To the extent that, for any 

particular Regular-Use Covered Flare, SDP has instrumentation 

capable of measuring and/or calculating the volumetric and mass 

flow rate of hydrogen, nitrogen, oxygen, carbon monoxide, carbon 

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ii. 

iii. 

iv. 

Document 2-1 Filed in TXSD on 07/10/13 Page 37 of 121 

dioxide, and/or water (steam) in the Waste Gas, SDP may break 

down the volumetric and mass flow as between: (i) All Waste Gas 

flows excluding hydrogen, nitrogen, oxygen, carbon monoxide, 

carbon dioxide, and/or water (steam); and (ii) hydrogen, nitrogen, 

oxygen, carbon monoxide, carbon dioxide, and/or water (steam) 

flows in the Waste Gas. SDP may use either an engineering 

evaluation or measurements from monitoring or a combination to 

determine flow rate. In determining flow rate, flows during all 

periods (including but not limited to normal operations and periods 

of Startup, Shutdown, Malfunction, process upsets, relief valve 

leakages, utility losses due to an interruptible utility service 

agreement, and emergencies arising from events within the 

boundaries of the Covered Facilities), except those described in the 

next sentence, shall be included. Flows that could not be 

prevented through reasonable planning and are in anticipation of or 

caused by a natural disaster, act of war or terrorism, or External 

Utility Loss are the only flows that shall be excluded from the 

calculation of flow rate. SDP shall specifically describe the date, 

time, and nature of the event that results in the exclusion of any 

flows from the calculation. 

Baseload Waste Gas Flow Rates. SDP shall utilize flow rate data 

for the one-year period of time prior to 31 days before the 

submission of the Initial WGMP to determine the Baseload Waste 

Gas Flow Rate, in scfd, to each Regular-Use Covered Flare. The 

Baseload Waste Gas Flow Rate shall not include flows during 

periods of Startup, Shutdown, and Malfunction. 

Identification of Constituent Gases. SDP shall use best efforts to 

identify the constituent gases within each Regular-Use Covered 

Flare’s Waste Gas and the percentage contribution of each such 

constituent during baseload conditions. SDP may use either an 

engineering evaluation or measurements from monitoring or a 

combination to determine Waste Gas constituents. 

Waste Gas Mapping. Using instrumentation, isotopic tracing, 

and/or engineering calculations, SDP shall identify and estimate 

the flow from each process unit header (sometimes referred to as a 

“subheader”) to the main header(s) servicing the Regular-Use 

Covered Flare. Using that information and all other available 

information, SDP shall complete an identification of each Waste 

Gas tie-in to the main header(s) and process unit header(s), as 

applicable, consistent with Appendix 1.11. Temporary 

connections to the main header(s) of a Regular-Use Covered Flare 

and/or process unit header(s) are not required to be included in the 

mapping. 

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c. Reductions previously realized. SDP shall describe the equipment, 

processes and procedures installed or implemented since 2008 to reduce flaring. The description 

shall specify the date of installation or implementation and the amount of reductions realized. 

d. Planned reductions. SDP shall describe the equipment, processes, or 

procedures that SDP plans to install or implement to eliminate or reduce flaring. The description 

shall specify a schedule for expeditious installation and commencement of operation and a 

projection of the amount of reductions to be realized. Subsequent to the submission of the 

WGMP, SDP may revise the installation and operation dates provided that SDP does so in 

writing to EPA within a reasonable time of determining that such a revision(s) is(are) necessary 

and provides a reasonable explanation for the revised date(s). In formulating this plan, SDP 

specifically shall review and evaluate the results of the Waste Gas Mapping required by 

Subparagraph 30.b.iv. 

e. Taking a Covered Flare Permanently Out of Service. SDP shall identify 

any Covered Flare that it intends to permanently take out of service, including the date for 

completion of the decommissioning. Taking a Covered Flare “permanently out of service” 

means physically removing piping in the Flare header or physically isolating the piping with a 

welded blind so as to eliminate direct piping to the Covered Flare and surrendering any permit to 

operate such Covered Flare. 

f. Prevention Measures. SDP shall describe and evaluate all Prevention 

Measures, including a schedule for the expeditious implementation and commencement of 

operation of all Prevention Measures, to address the following: 

i.	 Flaring that has occurred or may reasonably be expected to occur 

during planned maintenance activities, including Startup and 

Shutdown. The evaluation shall include a review of flaring that 

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has occurred during these activities since January 2009 and shall 

consider the feasibility of performing these activities without 

flaring. 

ii.	 Flaring that may reasonably be expected to occur due to issues of 

gas quantity and quality. The evaluation shall include a general 

audit of the existing flare gas recovery capacity of each 

Regular-Use Covered Flare, the storage capacity available for 

excess Waste Gases, and the scrubbing capacity available for 

Waste Gases including any limitations associated with scrubbing 

Waste Gases for use as fuel. 

iii.	 Flaring caused by the recurrent failure of air pollution control 

equipment, process equipment, or a process to operate in a normal 

or usual manner. The evaluation shall consider the adequacy of 

existing maintenance schedules and protocols for such equipment. 

A failure is “recurrent” if it occurs more than twice during any five 

year period as a result of the same cause. 

31. First Updated Waste Gas Minimization Plan. By no later than the dates set forth 

in Column E of Appendix 2.1, SDP shall submit to EPA a First Updated WGMP which shall 

update for the 12-month period after the period covered by the Initial Waste Gas Minimization 

Plan, if and as necessary, the information required in Subparagraphs 30.a–30.f and shall also 

include the following: 

a.	 Updated Waste Gas Mapping. SDP shall update the Waste Gas mapping 

as more information becomes available. SDP shall use this updated 

mapping to plan reductions; 

b.	 Reductions Based on Root Cause Analysis. SDP shall review all of the 

Root Cause Analysis reports submitted under Paragraph 35 to determine if 

reductions in addition to the reductions achieved through any required 

corrective action under Paragraph 36 can be realized; and 

c.	 Revised Schedule. To the extent that SDP proposes to extend any 

schedule set forth in the Initial WGMP, SDP may do so only with good 

cause. 

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32. Subsequent Updates to Waste Gas Minimization Plan. 

a. SDP Chemical Plant. In the first semi-annual report required under 

Section IX of this Decree (Reporting Requirements) that is due no sooner than one year after the 

submission of the First Updated WGMP, SDP shall submit a Second Updated WGMP for the 

SDP Chemical Plant. On an annual basis thereafter until termination of the Decree, SDP shall 

submit an updated WGMP for the SDP Chemical Plant as part of the semi-annual report. Each 

update shall update, if and as necessary, the information required in Subparagraphs 30.a–30.f, 

31.a, and 31.b. To the extent that SDP proposes to extend any schedule set forth in a previous 

WGMP for the SDP Chemical Plant, SDP may do so only with good cause. 

b. SDP Refinery. For the SDP Refinery, in lieu of submitting any updates to 

the Initial and First Updated WGMP under this Consent Decree, SDP shall comply with the Flare 

Management Plan requirements of NSPS Subpart Ja, 40 C.F.R. § 60.103a(a)–(b), by no later than 

November 11, 2015. 

33. Waste Gas Minimization Plan: Implementation. By no later than the dates 

specified in a WGMP, SDP shall implement the actions described therein. If (i) no 

implementation date and/or (ii) no completion date for actions that do not require ongoing 

implementation (such as the installation of a piece of a equipment) is (are) set forth in the 

WGMP, the implementation and/or completion date shall be deemed the date of the submission 

of the WGMP. 

34. Enforceability of WGMPs. The terms of each WGMP (including Initial, First 

Updated, and Subsequent Updated WGMPs) submitted under this Consent Decree are 

specifically enforceable. 

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35. Root Cause Analysis for Reportable Flaring Incident. 

a. Internal Reporting and Recordkeeping. Except as provided in 

Paragraphs 37 and 38.a, commencing on the dates set forth in the definition of “Reportable 

Flaring Incident” in Section III of this Decree (Definitions), by no later than forty-five days 

following the end of a Reportable Flaring Incident, SDP shall conduct an investigation into the 

Root Cause(s) of the Incident and prepare and keep as a record an internal report that shall 

include, at a minimum, the following: 

i. The date and time that the Reportable Flaring Incident started and 

ended; 

ii. The volume of Waste Gas flared and an estimate of the quantity of 

VOCs and SO2 that was emitted and the calculations that were 

used to determine that quantity; 

iii. The steps, if any, that SDP took to limit the duration of the 

Reportable Flaring Incident and quantity of VOC and/or SO2 

emissions associated therewith; 

iv. A detailed analysis that sets forth the root cause and all 

contributing causes of the Reportable Flaring Incident, to the 

extent determinable; 

v. An analysis of the measures, if any, that are available to reduce the 

likelihood of a recurrence of a Reportable Flaring Incident 

resulting from the same root cause or contributing causes in the 

future. The analysis shall discuss the alternatives, if any, that are 

available, the probable effectiveness and the cost of the 

alternatives, if an alternative is eliminated based on cost. Possible 

design and operation and maintenance changes shall be evaluated. 

If SDP concludes that corrective action(s) is (are) required under 

Paragraph 36, the report shall include a description of the action(s) 

and, if not already completed, a schedule for its (their) 

implementation, including proposed commencement and 

completion dates. If SDP concludes that corrective action is not 

required under Paragraph 36, the report shall explain the basis for 

that conclusion; and 

vi. To the extent that investigations of the causes and/or possible 

corrective actions still are underway 45 days after the Reportable 

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Flaring Incident, a statement of the anticipated date by which a 

follow-up report fully conforming to the requirements of this 

Paragraph shall be completed. 

b. Submitting Summary of Internal Flaring Incident Reports. In each 

semi-annual report due under Section IX of this Decree (Reporting Requirements), SDP shall 

include a summary of the following items for each Reportable Flaring Incident that occurred 

during the six-month period that the semi-annual report covers: 

i.	 Date; 

ii.	 Duration; 

iii.	 Amount of SO2 and VOC released; 

iv.	 Root Cause(s); 

v.	 Corrective Action(s) completed; 

vi.	 Corrective Action(s) still outstanding; and 

vii.	 An analysis of any trends identified by SDP in terms of the number 

of Incidents, the Root Causes, or the types of Corrective Action. 

36. Corrective Action Implementation. In response to any Reportable Flaring 

Incident, SDP shall take, as expeditiously as practicable, such interim and/or long-term 

corrective actions, if any, as are consistent with good engineering practice to minimize the 

likelihood of a recurrence of the root cause and all contributing causes of that Reportable Flaring 

Incident. 

37. In lieu of preparing a new report under Paragraph 35 and analyzing and 

implementing corrective action under Paragraph 36 for a Reportable Flaring Incident that has as 

its root cause the same root cause as a previously reported Reportable Flaring Incident, SDP may 

cross-reference and utilize the prior report and analysis when preparing the report required by 

Paragraph 35. 

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38. Overlapping Requirements. 

a. Root Cause Analysis and Corrective Action Requirements under SDP’s 

PRI Consent Decree. To the extent that a Reportable Flaring Incident that is triggered solely by 

the SO2 threshold in the definition of “Reportable Flaring Incident” also constitutes an Acid Gas 

or Hydrocarbon Flaring Incident under Shell’s PRI Consent Decree, SDP shall follow the 

provisions of Shell’s PRI Consent Decree, and not the provisions of this Decree, for addressing 

the incident, for as long as Shell’s PRI Consent Decree is in effect. 

b. Root Cause Analysis and Corrective Action Provisions of NSPS 

Subpart Ja. With respect to the Covered Flares at the SDP Refinery, SDP no longer shall be 

required to comply with the root cause analysis and corrective action provisions in 

Paragraphs 35–36 of this Consent Decree on and after November 11, 2015. At that time, SDP 

shall comply with the requirements of NSPS Subpart Ja, 40 C.F.R. § 60.103a(c)–(e). 

D. Flare Gas Recovery Systems at the SDP Refinery 

39. Flare Gas Recovery Systems at the SDP Refinery: Capacity and Start-Up Dates. 

By no later than the following dates for the following Regular-Use Covered Flares at the SDP 

Refinery, SDP shall complete installation and commence operation of the following Flare Gas 

Recovery Systems at the SDP Refinery: 

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FGRS ID Covered 

Flares 

FGRS 

Operating 

Design 

Capacity 

(kscfh) 

Total No. of 

Compressors 

(includes 

one Spare 

per FGRS) 

Capacity of 

each 

Compressor 

(kscfh) 

FGRS 

Total 

Capacity 

(kscfh) 

Date 

CPU North and 

West 

350 2 350 700 DOE 

Coker Coker 290 6 58 348 DOE 

EPF/Girbotol East 

Property 

and 

Girbotol 

500 2 500 1000 DOE 

40.	 Flare Gas Recovery Systems at the SDP Refinery: Operation. 

a.	 General. SDP shall operate each FGRS in a manner to minimize Waste 

Gas to the respective Covered Flares while ensuring safe refinery operations. SDP also shall 

operate each FGRS consistent with good engineering and maintenance practices and in 

accordance with its design and the manufacturer’s specifications. 

b.	 Requirements Related to Compressors Being Available for Operation 

and/or in Operation. By no later than December 31, 2014, SDP shall comply with the following 

requirements when Potentially Recoverable Gas is being generated: 

i.	 CPU and EPF/Girbotol Flare Gas Recovery Systems. For the CPU 

and East Property/Girbotol Flare Gas Recovery Systems, SDP 

shall have one Compressor Available for Operation and/or in 

operation 98% of the time and two Compressors Available for 

Operation and/or in operation 90% of the time. Periods of 

maintenance and subsequent restart on the Compressors within the 

CPU and/or EPF/Girbotol Flare FGRSs may be included in the 

amount of time that the Compressors are Available for Operation 

when determining compliance with the requirement to have two 

Compressors Available for Operation and/or in operation 90% of 

the time, provided that these periods shall not exceed 1344 hours 

per Compressor in a five-year rolling sum period, rolled daily. 

ii.	 Coker Flare Gas Recovery System. For the Coker Flare Gas 

Recovery System, SDP shall have five Compressors Available for 

Operation and/or in operation 95% of the time and four 

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iii. 

Compressors Available for Operation and/or in operation at all 

times. The following periods may be included in the amount of 

time that a Compressor is Available for Operation when 

determining compliance with the requirement to have four 

Compressors Available for Operation and/or in operation “at all 

times”: 

(1)	 Periods of maintenance on and subsequent restart of the 

equipment within the Coker FGRS that is shared by all 

Compressors (for example, the water seal, the knock-out 

drum, valves), such that the entire FGRS must be shut 

down in order to undertake the maintenance; provided 

however, that these periods shall not exceed 336 hours in a 

five-year rolling sum period, rolled daily. SDP shall use 

best efforts to schedule these maintenance activities during 

a turnaround of the process units venting to the Coker 

Flare. To the extent it is not practicable to undertake these 

maintenance activities during a turnaround, SDP shall use 

best efforts to minimize the generation of Waste Gas during 

such periods. 

(2)	 Periods in which the four Compressors are shut down 

(including the subsequent restart) due to operating 

conditions (such as high temperatures or large quantities of 

entrained liquid in the Vent Gas) outside the design 

operating range of the Coker FGRS, including the 

associated knock-out drum(s), such that the outage is 

necessary for safety and/or to preserve the mechanical 

integrity of the Coker FGRS. By no later than 45 days after 

any such period of outage, SDP shall investigate the root 

cause and all contributing causes of the outage and shall 

implement, as expeditiously as practicable, corrective 

action, if any, to prevent a recurrence of the cause(s). In 

the reports due under Section IX of this Decree, SDP shall 

describe each outage that occurred under the conditions 

identified in this Subparagraph, including the date, 

duration, cause(s), corrective action, and the status of the 

implementation of corrective action. 

Period to be Used for Computing Percentage of Time. For 

purposes of calculating compliance with the 90%, the 95%, and the 

98% of time that a Compressor or group of Compressors must be 

Available for Operation and/or in operation, as required by 

Subparagraphs 40.b.i and 40.b.ii, the period to be used shall be an 

8760-hour rolling sum, rolled hourly, using only hours when 

Potentially Recoverable Gas was generated during all or part of the 

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hour but excluding hours for flows that could not have been 

prevented through reasonable planning and were in anticipation of 

or caused by a natural disaster, act of war or terrorism, or External 

Utility Loss. When no Potentially Recoverable Gas was generated 

during an entire hour, then that hour shall not be used in computing 

the 8760-hour rolling sum. The rolling sum shall include only the 

prior 8760 1-hour periods when Potentially Recoverable Gas was 

generated during all or part of the hour, provided that the 

Potentially Recoverable Gas was not generated by flows that could 

not have been prevented through reasonable planning and were in 

anticipation of or caused by a natural disaster, act of war or 

terrorism, or External Utility Loss. 

E.	 Flaring Limitations at the SDP Refinery 

41.	 Limitations on Flaring at the SDP Refinery: Initial Limits. 

a.	 On and after the following dates, SDP shall comply with the following 

limitations on flaring from all SDP Refinery Covered Flares and Portable Flares (if any): 

i.	 Refinery-Wide 30-day Rolling Average. By no later than 

December 31, 2017, SDP shall comply with the following 

Refinery-wide short-term limit: 2,455,944 scfd of Waste Gas on a 

30-day rolling average basis, rolled daily. 

ii.	 Refinery-Wide 365-day Rolling Average. By no later than 

December 31, 2014, SDP shall comply with the following 

Refinery-wide long-term limit: 1,637,296 scfd of Waste Gas on 

365-day rolling average basis, rolled daily. 

iii.	 The rolling average period shall include only the prior 30 or 365 

days, as applicable, when any Refinery Covered Flare or Portable 

Flare was/were In Operation. 

Each exceedance of the 30-day rolling average limit or each exceedance of the 365-day rolling 

average limit shall constitute one day of violation. An exceedance of either or both of the limits 

shall not prohibit ongoing refinery operations. 

b.	 The limitations set forth in Subparagraph 41.a were calculated using the 

equations set forth in Subparagraph 43.a.i and ii. Appendix 2.3 sets forth the actual calculation. 

The “SDP Ref. Crude Capacity” was taken from the “Total Operable” atmospheric crude oil 

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distillation capacity, in barrels per calendar day, found in Part 5, Code 401, of the Form EIA-820 

that SDP submitted to the Energy Information Agency (“EIA”) for the 2012 report year. The 

value reported was 327,000 barrels per calendar day. A copy of that Form is included in 

Appendix 2.3. The “SDP Complexity” and “Industry Avg Complexity” were calculated pursuant 

to the methodology set forth in Appendix 1.14. 

42. Intentionally left blank. 

43. Limitations on Flaring at the SDP Refinery: Requesting an Increase in the 

Limit(s). 

a. SDP Request. Once per calendar year commencing no sooner than 

January 1, 2016, SDP may submit a request to EPA to increase the limitations in flaring set forth 

in Subparagraphs 41.a and/or 41.b. SDP may request an increase in the limit(s), and EPA will 

approve such an increase, only if the request is based on post-Lodging changes in crude capacity 

and/or complexity that are or will be permitted by the State of Texas and only if the changes in 

crude capacity and/or complexity result in new limit(s) that are higher by at least 20% than the 

limits set forth in Subparagraphs 41.a and/or 41.b. In any such request, SDP shall propose 

(a) new limit(s) (hereafter referred to as “New Limit(s) Based on Projections”) based upon the 

following equations: 

i. For the Refinery-wide, 30-day rolling average limit: 

Refinery Flaring	 ≤ 750,000 scfd x SDP Ref. Crude Cap. x SDP Complexity____ 

100,000 bpd Industry Avg Complexity 

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ii. For the Refinery-wide, 365-day rolling average limit: 

Refinery Flaring ≤ 500,000 scfd x SDP Ref. Crude Cap. x SDP Complexity 

100,000 bpd Industry Avg Complexity 

Nothing in this Paragraph or Consent Decree shall be construed to relieve SDP of an obligation 

to evaluate, under applicable Prevention of Significant Deterioration and Nonattainment New 

Source Review requirements, any increase in a Refinery-Wide limit on flaring. 

b.	 For purposes of Subparagraphs 43.a.i and 43.a.ii, the following shall 

apply: 

i.	 The items in italics are variables that will change over time. 

ii.	 The SDP Ref. Crude Capacity shall be determined as follows: 

(1)	 If the post-Lodging modification does not affect the crude 

capacity, the Atmospheric Crude Oil Distillation Capacity, 

in barrels per calendar day, that the Refinery reported under 

“Total Operable” capacity on Part 5, Code 401, of the 

Applicable Form EIA-820; the definition of “Applicable 

Form EIA-820” is found in the “Definitions” section of 

Appendix 1.14; to the extent that the “Parts” or “Codes” on 

Form EIA-820 change in the future, the intent of the Parties 

is that the “Parts” and “Codes” of future forms that 

correspond most closely to those found on the Form EIA820 for Report Year 2012 (see Attachment 2 to Appendix 

1.14) will be used; or 

(2)	 If the post-Lodging modification does affect crude 

capacity, the projected, new capacity set forth in the air 

permit application(s) for the post Lodging modification 

iii.	 SDP Complexity shall be calculated in accordance with Equation 1 

of Appendix 1.14. SDP shall certify the accuracy of the projected 

crude capacity and/or process unit capacities used to support the 

calculations. 

iv.	 The Industry Average Complexity shall be calculated in accordance 

with Equation 2 of Appendix 1.14. 

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c. EPA Response to Request. EPA shall evaluate any request under 

Subparagraph 43.a on the basis of consistency with Subparagraphs 43.a.i and 43.a.ii. If EPA 

does not act on SDP’s request within 90 days of submission, SDP may invoke the accelerated 

dispute resolution provisions of Subsection XII.B of this Decree. 

d. The New Limit(s) Based on Projections shall take effect, if ever, 

beginning on the later of the date that EPA approves the request or a dispute is resolved in SDP’s 

favor or the date(s) specified in the modification permit(s). 

e. In the event that SDP amends, modifies or withdraws the air permit 

application(s) that is/are the basis for the New Limit(s) Based on Projections requested pursuant 

to Subparagraph 43.a in a manner that affects the limit(s) calculation(s), SDP shall, within 15 

days of amending, modifying, or withdrawing its air permit application(s), revise or withdraw its 

request under Subparagraph 43.a. To the extent that SDP revises, rather than withdraws, its 

request under Subparagraph 43.a, the 90-day deadline under Subparagraph 43.c for EPA’s 

response to the revised request shall commence upon the date of EPA’s receipt of SDP’s revised 

request. 

f.	 Consequences of a Mistake in Projected Capacities. 

i.	 By no later than 30 days after the Startup of the permitted 

modifications, SDP shall determine whether the projected “SDP 

Ref. Crude Capacity” or the projected capacities for new or 

modified units that SDP relied upon pursuant to 

Subparagraphs 43.b.ii and/or b.iii, respectively, were or are 

different from the actual capacities that SDP has or will report to 

the EIA or the Oil & Gas Journal after the Startup of the permitted 

modification. If there are differences, SDP shall re-calculate the 

flaring limitation(s) using the actual capacities that SDP has or will 

report to the EIA or the Oil & Gas Journal (hereafter referred to as 

“New Limit(s) Based on Actuals”). 

ii.	 If the New Limit(s) Based on Actuals that SDP calculates under 

Subparagraph 43.f.i is/are greater than the New Limit(s) Based on 

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Projections that SDP calculated under Subparagraph 43.a, then no 

further action shall be required and the New Limit(s) Based on 

Projections shall remain in effect. 

iii.	 If the New Limit(s) Based on Actuals that SDP calculates under 

Subparagraph 43.f.i is/are less than the New Limit(s) Based on 

Projections that SDP calculated under Subparagraph 43.a, then by 

no later than 30 days after the Startup of the permitted 

modifications, SDP shall: (1) commence complying with the New 

Limit(s) Based on Actuals; and (2) submit the revised, recalculated 

New Limit(s) Based on Actuals to EPA. After submission to EPA, 

SDP shall consult with EPA about the New Limit(s) Based on 

Actuals and secure EPA’s approval. 

iv.	 Stipulated Penalties. If Subparagraph 43.f.iii applies, then by no 

later than 60 days after the Startup of the permitted modifications, 

the New Limit(s) Based on Actuals identified in the submission to 

EPA under Subparagraph 43.f.iii(2) shall apply and form the basis 

for determining compliance for purposes of the stipulated penalty 

provisions of Subparagraphs 93.l and 93.m. If EPA disapproves 

the New Limit(s) Based on Actuals, the New Limit(s) Based on 

Actuals shall continue to apply for purposes of stipulated penalties 

until such time as other limitation(s) either is/are agreed upon 

between EPA and SDP or a dispute is resolved that sets forth 

revised limitation(s). 

44.	 Limitations on Flaring at the SDP Refinery: Meaning and Calculation of “Waste 

Gas” Flow for Purposes of the Limitation on Flaring. For purposes of the meaning and 

calculation of “Waste Gas” flow in the limitations on flaring in Subparagraphs 41.a.i and 41.a.ii, 

and any revised limitations on flaring developed pursuant to Paragraph 43, the following shall 

apply: 

a.	 To the extent that SDP has instrumentation capable of calculating the 

volumetric flow rate of hydrogen, nitrogen, oxygen, carbon monoxide, 

carbon dioxide, and/or water (steam) in the Waste Gas, the contribution of 

all measured flows of any of these elements/compounds may be excluded 

from the Waste Gas flow rate calculation. 

b.	 Flows during all periods (including but not limited to normal operations 

and periods of Startup, Shutdown, Malfunction, process upsets, relief 

valve leakages, utility losses due to an interruptible utility service 

agreement, and emergencies arising from events within the boundaries of 

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the Refinery), except those expressly described in the next sentence, shall 

be included. Flows that could not be prevented through reasonable 

planning and are in anticipation of or caused by a natural disaster, act of 

war or terrorism, or External Utility Loss may be excluded from the 

calculation of flow rate. 

c.	 Except for hydrogen, nitrogen, oxygen, carbon monoxide, carbon dioxide, 

and/or water (steam) contributions to the flow rate that are excluded by 

virtue of instrumentation measuring these flows, for any flow that SDP 

does not include in a computation, SDP shall submit the following 

information in the semi-annual report due under Paragraph 85 of this 

Consent Decree: a description of the event that resulted in the exclusion; 

the date(s) and duration(s) of the flows caused by the event; the estimated 

VOC and SO2 emissions during the event; whether flows from the event 

are anticipated to persist after the notice, and if so, for how long; and the 

measures taken or to be taken to prevent or minimize the flows, including, 

for future anticipated flow, the schedule by which those measures will be 

implemented. 

F.	 Flare Gas Recovery System at the Olefins Flares of the SDP Chemical Plant 

45.	 Olefins FGRS: Capacity and Start-Up Date. 

a.	 By no later than December 31, 2017, SDP shall complete installation and 

commence operation of one or more Flare Gas Recovery System(s) for the Olefins Flares. 

Except as provided in Paragraph 46, the Operating Design Capacity of the Olefins FGRS(s) shall 

be a minimum of 270 kscfh. 

b.	 The design of each Olefins FGRS shall include one installed Duplicate 

Spare Compressor. 

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46. Process of Securing a Decrease in the Operating Design Capacity of the Olefins 

FGRS. 

a. SDP Request for an Operating Design Capacity of Less than 270 kscfh. 

Pursuant to the requirements of Subsection V.C of this Consent Decree (“Waste Gas 

Minimization”), SDP shall undertake efforts to minimize Waste Gas flow to, inter alia, the 

Olefins Flares. Because of those activities, by no later than SDP’s submission of its First 

Updated WGMP, SDP may submit a request to EPA for approval of a decrease in the 270 kscfh 

Operating Design Capacity of the Olefins FGRS. In any such request, SDP must: 

i.	 Continue to commit to install (a) Duplicate Spare Compressor(s) 

consistent with the requirements of Paragraph 45.b; and 

ii.	 Demonstrate that the newly requested Operating Design Capacity 

and number of compressors of the Olefins FGRS will result in an 

Estimated Percent Recovery of 80% or more as calculated in 

accordance with the Paragraph 46.b. 

b. Calculation of Estimated Percent Recovery. In undertaking the 

demonstration required in Subparagraph 46.a.ii, SDP shall use the hourly average Vent Gas 

flow-adjusted data set (“HFvg-adjusted data set”), as defined below, to calculate the Estimated 

Percent Recovery in accordance with the methodology specified in Appendix 2.4. In addition, 

the following shall apply: 

i.	 SDP shall submit, in editable spreadsheet form, the hourly average 

Vent Gas flow data set for each hour of the year that ends 30 days 

prior to the date of SDP’s request for EPA approval of a decrease 

in the Operating Design Capacity of the Olefins FGRS (“HFvgbaseline data set”). 

ii.	 To account for Vent Gas flow reductions that SDP will secure 

from specific sources of Vent Gas as a result of identified 

modifications and/or identified revised operating practices that 

SDP, in its request for a decrease in the Olefins FGRS Operating 

Design Capacity, commits to complete between the date of its 

request and December 31, 2017, SDP shall adjust each hourly 

average Vent Gas flow rate in the HFvg-baseline data set by 

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iii. 

iv. 

v. 

subtracting out the contribution to the flow from specific sources 

of Vent Gas that SDP commits to eliminate, i.e., “Enforceable 

Reductions.” SDP shall also submit an adjusted Hourly Average 

Vent Gas flow data set (“HFvg-adjusted data set”) that represents 

the HFvg-baseline data set as adjusted by the identified 

Enforceable Reductions. The HFvg-adjusted data set shall be 

submitted in editable spreadsheet form and shall include the hourly 

average Vent Gas flow data set as adjusted for each hour of the 

year that ends 30 days prior to the request for a decrease in the 

Olefins FGRS Operating Design Capacity. 

SDP shall assume that the amount of time that the proposed size 

and number of Compressors will be “Available for Operation” will 

equal the percentages specified in Subparagraph 47.b. 

“Enforceable Reductions” shall mean reductions in the Vent Gas 

Flow that SDP shall secure from specific sources of Vent Gas as a 

result of identified modifications and/or identified revised 

operating practices that SDP, in its request for a decrease in the 

Olefins FGRS Operating Design Capacity, commits to complete 

between the date of its request and December 31, 2017. To the 

extent that SDP commenced implementation of any such 

modifications and/or revised operating practices prior to its request 

but the resulting Vent Gas Flow reductions were not yet realized 

and included in the Vent Gas Flow for the full one year period that 

is 30 days prior to the request, SDP may include them in the 

Enforceable Reductions. In its request, SDP shall include 

documentation supporting the scope and expected flow 

reduction(s) from the modifications and/or revised operating 

practices and a schedule for the implementation of these activities 

prior to December 31, 2017. 

“Vent Gas Flow,” for all purposes in the equations used in this 

Paragraph, shall include flows during all periods (including but not 

limited to normal operations and periods of Startup, Shutdown, 

Malfunction, process upsets, relief valve leakages, External Utility 

Losses due to an interruptible utility service agreement, and 

emergencies arising from events within the boundaries of the 

Facilities), except those described in the next sentence. Vent Gas 

Flows that could not be prevented through reasonable planning and 

are in anticipation of or caused by a natural disaster, act of war or 

terrorism, or External Utility Loss are the only flows that shall be 

excluded from the calculation of flow. In making its request for a 

smaller Operating Design Capacity for the Olefins FGRS, SDP 

specifically shall describe the date, time, and nature of any event 

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that results in the exclusion of any Vent Gas Flows from its 

calculation. 

c. EPA Response to Request. EPA shall evaluate any request under 

Subparagraphs 46.a and b on the basis of its consistency with the requirements of those 

Subparagraphs. If EPA does not act on SDP’s request within 90 days of submission, SDP may 

invoke the accelerated dispute resolution provisions of Subsection XII.B of this Decree. The 

new Design Operating Capacity shall take effect, if ever, on the date that EPA approves the 

request or a dispute is resolved in SDP’s favor. 

47.	 Olefins FGRS: Operation. 

a. General. After the December 31, 2017 deadline in Paragraph 45.a, SDP 

shall operate the Olefins FGRS(s) in a manner to minimize Waste Gas to the Olefins Flares while 

ensuring safe chemical plant operations. SDP also shall operate the Olefins FGRS consistent 

with good engineering and maintenance practices and in accordance with its design and the 

manufacturer’s specifications. 

b. Requirements Related to Compressors Being Available for Operation. By 

no later than June 30, 2018, SDP shall comply with the following requirements for the Olefins 

FGRS when Potentially Recoverable Gas is being generated: 

i.	 An Olefins FGRS with two (2) Compressors (one of which is the 

required Duplicate Spare Compressor) shall have one compressor 

Available for Operation and/or in operation 98% of the time and 

two Compressors Available for Operation and/or in operation 90% 

of the time. If these two Compressors are reciprocating 

Compressors, periods of maintenance on them and subsequent 

restart may be included in the amount of time that the Compressors 

are Available for Operation when determining compliance with the 

requirement to have two Compressors Available for Operation 

and/or in operation 90% of the time; provided however, that these 

periods shall not exceed 1344 hours per Compressor in a five-year 

rolling sum period, rolled daily. 

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ii. 

iii. 

An Olefins FGRS with more than two (2) Compressors (one of 

which is the required Duplicate Spare Compressor) where the total 

number of Compressors is represented by “n,” shall have n-1 

Compressors Available for Operation and/or in operation 95% of 

the time and n-2 Compressors Available for Operation and/or in 

operation at all times. The following periods may be included in 

the amount of time that a Compressor is Available for Operation 

when determining compliance with the requirement to have “n-2” 

Compressors Available for Operation and/or in operation “at all 

times”: 

(1)	 Periods of maintenance on and subsequent restart of the 

equipment within the Olefins FGRS that is shared by all 

Compressors (for example, the water seal, the knock-out 

drum, valves), such that the entire FGRS must be shut 

down in order to undertake the maintenance; provided 

however, that these periods shall not exceed 336 hours in a 

five-year rolling sum period, rolled daily. SDP shall use 

best efforts to schedule these maintenance activities during 

a turnaround of the Olefins unit. To the extent it is not 

practicable to undertake these maintenance activities during 

an Olefins turnaround, SDP shall use best efforts to 

minimize the generation of Waste Gas during such periods. 

(2)	 Periods in which the “n-2” Compressors are shut down 

(including the subsequent restart) due to operating 

conditions (such as high temperatures or large quantities of 

entrained liquid in the Vent Gas) outside the design 

operating range of the Olefins FGRS, including the 

associated knock-out drum(s), such that the outage is 

necessary for safety and/or to preserve the mechanical 

integrity of the Compressors. By no later than 45 days after 

any such outage, SDP shall investigate the root cause and 

all contributing causes of the outage and shall implement, 

as expeditiously as practicable, corrective action, if any, to 

prevent a recurrence of the cause(s). In the reports due 

under Section IX of this Decree, SDP shall describe each 

outage that occurred under the conditions identified in this 

Subparagraph, including the date, duration, cause(s), 

corrective action, and the status of the implementation of 

corrective action. 

Period to be Used for Computing Percentage of Time. For 

purposes of calculating compliance with the 90%, the 95%, and the 

98% of time that a Compressor or group of Compressors must be 

Available for Operation and/or in operation, as required by 

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Subparagraphs 47.b.i and 47.b.ii, the period to be used shall be an 

8760-hour rolling sum, rolled hourly, using only hours when 

Potentially Recoverable Gas was generated during all or part of the 

hour but excluding hours for flows that could not have been 

prevented through reasonable planning and were in anticipation of 

or caused by a natural disaster, act of war or terrorism, or External 

Utility Loss. When no Potentially Recoverable Gas was generated 

during an entire hour, then that hour shall not be used in computing 

the 8760-hour rolling sum. The rolling sum shall include only the 

prior 8760 1-hour periods when Potentially Recoverable Gas was 

generated during all or part of the hour, provided that the 

Potentially Recoverable Gas was not generated by flows that could 

not have been prevented through reasonable planning and were in 

anticipation of or caused by a natural disaster, act of war or 

terrorism, or External Utility Loss. 

G. Limitations on Flaring at the A&S and HIPA Flares of the SDP Chemical Plant 

48. Conversion of A&S Flare to a Temporary -Use Flare. By no later than June 30, 

2013, SDP will convert the A&S Flare to a Temporary-Use Flare by rerouting flow from the 

A&S Flare to the HIPA Flare. 

49. Limitation on VOC Emissions from the HIPA Flare. By no later than 24 months 

after the Date of Entry, SDP shall not emit from the HIPA Flare more than 25 tons per year of 

VOCs in a 365-day rolling sum period, rolled daily. SDP shall utilize the equations set forth in 

Appendix 2.5 to calculate VOC emissions from the HIPA flare in any given 365-day rolling sum 

period. After incorporation of the limit into a federally-enforceable permit, nothing in this 

Consent Decree shall prohibit SDP from seeking an increase in this limit (regardless of the 

amount of the increase) prior to termination of this Consent Decree if SDP undertakes a LAER 

analysis through appropriate Texas state permitting authorities in order to secure the increase. 

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H. Flare Combustion Efficiency 

50. General Emission Standards Applicable to Covered Flares. By no later than the 

dates set forth in Column F of Appendix 2.1, SDP shall comply with the requirements set forth in 

this Paragraph at all times when the Covered Flare is In Operation. 

a. Operation during Emissions Venting. SDP shall operate each Covered 

Flare at all times when emissions may be vented to it. 

b. No Visible Emissions. Except for periods of Startup, Shutdown, and/or 

Malfunction, SDP shall operate each Covered Flare with no Visible Emissions. Method 22 in 

40 C.F.R. Part 60, Appendix A, shall be used to determine compliance with this standard. 

However, for purposes of this Consent Decree, Visible Emissions may be determined by a 

person certified pursuant to Method 22 or documented by a video camera. 

c. Flame Presence. SDP shall operate each Covered Flare with a flame 

present at all times. SDP shall monitor the presence of the pilot flame using a thermocouple or 

any other equivalent device to detect the presence of the pilot flame. 

d. Monitoring According to Applicable Provisions. SDP shall comply with 

all applicable Subparts of 40 C.F.R. Parts 60, 61, or 63 that state how a particular Covered Flare 

must be monitored. 

e. Good Air Pollution Control Practices. At all times, including during 

periods of Startup, Shutdown, and/or Malfunction, SDP shall implement good air pollution 

control practices to minimize emissions from each Covered Flare; provided however, that SDP 

shall not be in violation of this requirement for any practice that this Consent Decree requires 

SDP to implement after the Date of Lodging for the period between the Date of Lodging and the 

implementation date or compliance date (whichever is applicable) for the particular practice. 

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51. Exit Velocity. Beginning no later than the dates set forth in Column C of 

Appendix 2.1, except for periods of Startup, Shutdown, and/or Malfunction, SDP shall operate 

each Covered Flare with an Exit Velocity less than 18.3 m/sec (60 ft/sec) on a one-hour block 

average; provided however, that: 

a.	 If the Covered Flare combusts Vent Gas with a Net Heating Value of 

greater than 1000 BTU/scf, SDP may operate the Covered Flare with an 

Exit Velocity equal to or greater than 18.3 m/sec (60 ft/sec) but less than 

122 m/sec (400 ft/sec) on a one-hour block average; and 

b.	 If the Covered Flare has a maximum permitted velocity (Vmax), SDP may 

operate the Covered Flare with an Exit Velocity less than Vmax provided 

that it also operates the applicable Flare with an Exit Velocity of less than 

122 m/sec (400 ft/sec) on a one-hour block average. Vmax shall be 

calculated in accordance with 40 C.F.R. § 60.18(f)(5). The Unobstructed 

Cross Sectional Area of the Flare Tip shall be calculated consistent with 

Appendix 1.6. 

52. Revisions to 40 C.F.R. §§ 60.18(b)–(f) and/or 63.11(b). To the extent that, from 

the Date of Lodging of this Consent Decree until its termination, revisions to 40 C.F.R. 

§§ 60.18(b)–(f) and/or 63.11(b) are final and effective that are inconsistent with any of the 

requirements in Paragraphs 50.a–d or 51, then SDP shall comply with the final, effective 

regulations and any requirements in Paragraphs 50.a–d and/or 51 that are not inconsistent with 

these final, effective regulations. As used in this Paragraph, “inconsistent” mean that compliance 

with both provisions is not possible. 

53.	 Work Practice Standards for each Covered Flare. 

a. Regular-Use Covered Flares. By no later than the dates set forth in 

Column G of Appendix 2.1, utilizing the instrumentation and controls required to be installed 

pursuant to Paragraphs 18–24, SDP shall install on each Regular-Use Covered Flare an 

Automatic Control System that shall: 

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i. Automate the control of the Supplemental Gas flow rate to the 

respective Flare; and 

ii. Automate the control of the Total Steam Mass Flow Rate to the 

respective Flare. 

For the Regular-Use Covered Flares, SDP shall operate these Automated Control Systems 

immediately upon installation. 

b. Temporary-Use Covered Flares. After the dates set forth in Column G of 

Appendix 2.1, SDP shall not direct any Sweep, Supplemental, and/or Waste Gas to any 

Temporary-Use Flare, until an Automatic Control System that conforms to the requirements of 

Subparagraph 53.a is installed. SDP shall operate the Automated Control System whenever any 

Sweep, Supplemental, and/or Waste Gas is directed to the Temporary-Use Covered Flare. 

During those periods after the installation of the ACS when the Temporary-Use Covered Flare is 

not Capable of Receiving Sweep, Supplemental and/or Waste Gas, the operation of the ACS is 

not required; provided however, that prior to the Startup of a Temporary-Use Covered Flare, 

SDP shall take all necessary steps to ensure that the ACS is capable of continuous operation for 

the full duration of the use of the Temporary-Use Covered Flare. 

54. Exception to Work Practice Standards in Subparagraph 53. SDP manually may 

override the operation of the Automatic Control System(s) required in Subparagraph 53 if the 

exception in Paragraph 60 applies, and/or during Startup, Shutdown, or Malfunction of a 

Covered Flare or a process unit that feeds a Covered Flare, and/or to achieve the following: 

a. Stop Smoke Emissions that are occurring; 

b. Meet the Net Heating Value requirements of Paragraph 56; 

c. Prevent extinguishing the Flare; 

d. Protect personnel and process safety; 

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e. Stop Discontinuous Wake Dominated Flow; and/or 

f. Stop acoustic disturbances that are occurring. 

55. Operation According to Design. By no later than the dates set forth in Column H 

of Appendix 2.1, SDP shall operate and maintain each Covered Flare in accordance with its 

design, except if, and only to the extent that, operation and maintenance of the Covered Flare in 

conformance with its design conflicts with compliance with one or more of the requirements of 

this Consent Decree 

56. Net Heating Value Standards. 

a. Net Heating Value of Vent Gas (NHVvg). Beginning on the Date of 

Lodging and continuing until the earlier of: (i) termination of this Consent Decree; or (ii) the 

requirements in 40 C.F.R. §§ 60.18(c)(3)(ii) and 63.11(b)(6)(ii) related to the NHVvg are 

modified, SDP shall operate each Covered Flare, except as provided in Paragraph 60, with an 

NHVvg of greater than or equal to 300 BTU/scf at all times that the gas being combusted in the 

Covered Flare is subject to the control requirements of 40 C.F.R. § 60.18(c)(3)(ii) and/or 

§ 63.11(b)(6)(ii). 

b. Net Heating Value of Combustion Zone Gas (NHVcz) for Regular-Use 

Covered Flares, excluding the Olefins Ground Flare. By no later than the dates set forth in 

Column H of Appendix 2.1, and except as provided in Paragraph 60.a, SDP shall calculate an 

NHVcz-limit at each Regular-Use Covered Flare no less frequently than every fifteen minutes. 

Except as provided in Paragraph 60.a, SDP shall operate each Regular-Use Covered Flare so as 

to ensure that the Regular-Use Covered Flare’s NHVcz, on a three-hour rolling average, rolled 

every fifteen minutes, is greater than or equal to its NHVcz-limit on a three-hour rolling average, 

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rolled every fifteen minutes. SDP shall utilize the equations and directives set forth in 

Appendix 1.3 to meet the requirements of this Subparagraph 56.b. 

c. Net Heating Value of Combustion Zone Gas (NHVcz) for the Olefins 

Ground Flare. By no later than the date set forth in column H of Appendix 2.1, and except as 

provided in Paragraph 60.a, SDP shall calculate the NHVcz at the Olefins Ground Flare no less 

frequently than every 15 minutes. Except as provided in Paragraph 60.a, SDP shall operate the 

Olefins Ground Flare so as to ensure that its NHVcz, on a three-hour rolling average basis, rolled 

every fifteen minutes, is equal to or greater than 500 BTU/scf, using a Net Heating Value for 

hydrogen of 1212 BTU/scf. SDP shall utilize Steps 3 and 6 in Appendix 1.3 to calculate NHVcz. 

d. Net Heating Value of Combustion Zone Gas (NHVcz) for Temporary-Use 

Covered Flares. After the dates set forth in Column H of Appendix 2.1, SDP shall not direct any 

Sweep, Supplemental, and/or Waste Gas to any Temporary-Use Flare unless SDP calculates the 

NHVcz at such Temporary-Use Flare during its operation, except as provided in Paragraph 60.b. 

SDP may use either a gas chromatograph or Net Heating Value Analyzer to calculate/measure 

the Net Heating Value of the Vent Gas. If SDP uses a gas chromatograph to calculate Net 

Heating Value, SDP shall use a Net Heating Value for hydrogen of 1212 BTU/scf and shall 

calculate the NHVcz no less frequently than every 15 minutes. If SDP uses a Net Heating Value 

Analyzer to measure Net Heating Value of the Vent Gas, SDP shall calculate the NHVcz no less 

frequently than every five minutes. Except as provided in Paragraph 60.b, SDP shall operate 

each Temporary-Use Covered Flare so as to ensure that its NHVcz is greater than or equal to 355 

BTU/scf: (i) on a three-hour rolling average basis, rolled every fifteen minutes if a gas 

chromatograph is used; (ii) on a one-hour rolling average basis, rolled every five minutes, if a 

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Net Heating Value Analyzer is used. SDP shall utilize Steps 3 and 6 in Appendix 1.3 to 

calculate NHVcz. 

57. S/VG Standards (Total-Steam-to-Vent-Gas Ratio Standards). 

a. Interim Period. Beginning on the Date of Lodging and continuing until 

the dates set forth in Column H of Appendix 2.1, and except as provided in Subparagraph 57.c 

and Paragraph 60, SDP shall use best efforts to operate each Covered Flare at less than or equal 

to an S/VGmass of 3.0 on a one-hour rolling average, rolled every five minutes. 

b. After Interim Period. By no later than the dates set forth in Column H of 

Appendix 2.1, and except as provided in Subparagraph 57.c and Paragraph 60, SDP shall operate 

each Covered Flare at less than or equal to an S/VGmass of 3.0 on a one-hour rolling average, 

rolled every five minutes. For each Covered Flare, SDP shall record the S/VGmass. 

c. Exceptions. Notwithstanding the requirements of Subparagraphs 57.a and 

57.b, SDP is not subject to the emissions standards in those Subparagraphs if the exception in 

Paragraph 60 applies and/or in order to achieve the following: 

i. Stop Smoke Emissions that are occurring; 

ii. Meet the Net Heating Value requirements of Paragraph 56; 

iii. Prevent extinguishing the Flare; and/or 

iv. Protect personnel and process safety. 

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58. Prohibition on Discontinuous Wake Dominated Flow or Requirement for 

Minimum Momentum Flux Ratio (“MFR”) for Covered Flares. 

a. The requirements of this Paragraph have no applicability to Ground 

Flares; therefore, the Olefins Ground Flare is not subject to this Paragraph. All references to 

“Covered Flares” in this Paragraph exclude the Olefins Ground Flare. 

b. By no later than the dates set forth in Column H of Appendix 2.1, for each 

Covered Flare, SDP shall comply with either Subparagraph 58.c. or 58.d. In the first 

semi-annual report due after the applicable compliance date, SDP shall identify which 

compliance option it selects for each Covered Flare. SDP may select different alternatives for 

different Covered Flares and may change its election for any given Covered Flare by providing 

EPA with 30 days prior notice of the change. The notice shall include the reasons SDP is 

changing its compliance option. 

c.	 Prohibition on Discontinuous Wake Dominated Flow. 

i.	 SDP shall not operate the Covered Flares with Discontinuous 

Wake Dominated Flow (as defined above and in Appendix 1.12 of 

the Consent Decree), except for periods not to exceed a total of 

five minutes during any two consecutive hours. SDP shall add 

Supplemental Gas as necessary to prevent such instances of 

Discontinuous Wake Dominated Flow at the Covered Flares. 

ii.	 Prior to the effective date of the prohibition in Subparagraph 58.c.i, 

for all operators and supervisors with responsibility and/or 

oversight for the operation of each Covered Flare, SDP shall 

complete training on the meaning and prevention of Discontinuous 

Wake Dominated Flow. After this effective date, operators shall 

monitor the operation of each Covered Flare at intervals 

appropriate for the weather conditions and service of the Covered 

Flare in order to comply with the prohibition in 

Subparagraph 58.c.i. 

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d.	 MFR Requirements. MFR shall be calculated in accordance with the 

equations, conversion factors, MFR constants, MFR measured variables, and MFR calculated 

variables set forth in Appendix 1.5. SDP shall either: 

i.	 Maintain a minimum MFR of 0.0010 for the Olefins II and 

Olefins III Flares and a minimum MFR of 0.0030 for all other 

Covered Flares, each on a 60-minute rolling average, rolled every 

5 minutes; or 

ii.	 Propose a Flare-specific minimum MFR. SDP shall submit such a 

proposal to EPA for approval. In any such proposal, SDP shall 

demonstrate, using, at a minimum, photographs correlated to MFR, 

that at the proposed minimum MFR, Discontinuous Wake 

Dominated Flow will not occur for the Covered Flare that is the 

subject of the request. 

iii.	 Calculation of MFR “on a 60-minute rolling average, rolled every 

5 minutes,” when there are more than 5 but less than 12 

consecutive 5 minute averages of MFR. During any period of 

Vent Gas flow to the Covered Flare when there are more than 5 but 

less than 12 consecutive 5 minute averages of MFR, the MFR “on 

a 60-minute rolling average, rolled every 5 minutes” shall be 

calculated using the 5-minute averages that are greater than “0” 

during the period and for which the exception in Paragraph 58.e 

does not apply; the 5-minute averages when MFR is “0” because 

either there is no Vent Gas flow or the exception in Paragraph 58.e 

applies shall not be used in calculating the 60-minute rolling 

average, rolled every 5 minutes. 

e.	 Exceptions to the Prohibition on Discontinuous Wake Dominated Flow 

and MFR Requirements. Notwithstanding Subparagraphs 58.c. and 58.d, SDP shall not be 

required to add Supplemental Gas, and the requirements in those Subparagraphs are not 

applicable, at any time that Paragraph 60 applies and/or the wind speed at the Covered Facilities 

is greater than or equal to 35 mph on a 60-minute rolling average, rolled every 5 minutes. 

59.	 98% Combustion Efficiency. By no later than the dates set forth in Column H of 

Appendix 2.1, SDP shall operate each Covered Flare with a minimum of a 98% Combustion 

Efficiency at all times when Waste Gases are vented to it. To demonstrate continuous 

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compliance with the 98% Combustion Efficiency, SDP shall operate each Covered Flare in 

compliance with the applicable requirements in Paragraphs 56–58. 

60. Exception for Instrument Downtime. 

a. Regular-Use Covered Flares. For Regular-Use Covered Flares, a failure to 

comply with the work practices or standards in Subparagraphs 53.a, 56.a, 56.b, 56.c, 57.a, 57.b, 

58.c, or 58.d shall not constitute a violation of such work practice or standard if the 

noncompliance results from downtime of instruments or equipment due to the following: 

i. Malfunction of an instrument, for an instrument needed to meet the 

requirement(s); 

ii. Maintenance following instrument Malfunction, for an instrument 

needed to meet the requirement(s); 

iii. Scheduled maintenance of an instrument in accordance with the 

manufacturer’s recommended schedule, for an instrument needed 

to meet the requirement(s); and/or 

iv. Quality Assurance/Quality Control activities on an instrument 

needed to meet the requirement(s). 

This exception shall no longer be applicable if the activities in Subparagraphs 60.a.i–60.a.iv 

exceed 110 hours in any calendar quarter for any instrument. The calculation of instrument 

downtime shall be made in accordance with 40 C.F.R. § 60.13(h)(2) and Paragraph VI of 

Appendix 1.10. 

b. Temporary-Use Covered Flares and Portable Flares. For Temporary-Use 

Covered Flares and Portable Flares, a failure to comply with the work practices or standards in 

Subparagraphs 53.b, 56.a, 56.d, 57.a, 57.b, 58.c, or 58.d shall not constitute a violation of such 

work practice or standard if the noncompliance results from downtime of instruments or 

equipment due to the activities in Subparagraphs 60.a.i–iv; provided however, that this exception 

shall no longer be applicable if the activities in Subparagraphs 60.a.i–iv exceed 5% of the time 

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that the Temporary-Use Covered Flare or Portable Flare is In Operation and capable of receiving 

Waste, Supplemental, and/or Sweep Gas during an uninterrupted time period. The calculation of 

instrument downtime shall be made in accordance with 40 C.F.R. § 60.13(h)(2) and Paragraph 

VI of Appendix 1.10. 

61. Inapplicability of Paragraphs 56–59. The requirements of Paragraphs 56–59 are 

not applicable to any Covered Flare or Portable Flare when the only gas or gases being vented to 

the Covered Flare or Portable Flare is/are Pilot Gas and/or Purge Gas. 

62. Recordkeeping: Timing and Substance. SDP shall comply with the following 

recordkeeping requirements: 

a. By no later than three months after the dates set forth in Column C of 

Appendix 2.1, SDP shall calculate and record each of the following parameters: 

i.	 Total Steam Volumetric Flow Rate (in scfm) and Total Steam 

Mass Flow Rate (in lb/hr) (in accordance with the recording and 

averaging times required in Paragraph 27) 

ii.	 Vent Gas Volumetric Flow Rate (in scfm) and Vent Gas Mass 

Flow Rate (in lb/hr) (in accordance with the recording and 

averaging times required in Paragraph 27) 

iii.	 S/VGmass (in lb steam/lb Vent Gas) (in accordance with the 

averaging times in Subparagraph 57.b) 

iv.	 NHVvg (in BTU/scf) (on a one-hour block average) 

v.	 NHVcz (in BTU/scf) (in accordance with the averaging times in 

Subparagraphs 56.b, 56.c, and 56.d) 

vi.	 NHVcz-limit (in BTU/scf) (in accordance with the averaging times in 

Subparagraphs 56.b) 

b. By no later than six months after the first full calendar quarter starting on 

or after the dates set forth in Column C of Appendix 2.1, commencing if and when the excepted 

activities in Subparagraphs 28.a–28.d for any instrument subject to Paragraph 28 exceed 110 

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hours in any calendar quarter for a Regular-Use Covered Flare, or 5% of the time that a 

Temporary-Use Covered Flare is In Operation and Capable of Receiving Sweep, Supplemental, 

and/or Waste Gas during an uninterrupted time period, SDP shall record the duration of the 

deviation, an explanation of the cause(s) of the deviation, and a description of the corrective 

action(s) that SDP took. 

c. By no later than the dates set forth in Column G of Appendix 2.1 for 

compliance with the work practice standards in Paragraph 53: (i) SDP shall record each time it 

manually overrides an Automatic Control System, including the date, time, duration, reason for 

the override, and corrective actions that SDP took; and (ii) where the reason for the override was 

to stop Smoke Emissions that were occurring and/or to stop Discontinuous Wake Dominated 

Flow, SDP shall include a copy of the digital video record (with a time stamp) of the flare during 

the period of the manual override. 

d. By no later than the dates required in Column F of Appendix 2.1 for 

compliance with the standards in Paragraph 50, and by no later than the dates required in 

Column H of Appendix 2.1 for compliance with the emissions standards in Paragraphs 56–59, at 

any time that SDP deviates from those standards, SDP shall record the duration of the deviation, 

an explanation of the cause(s) of the deviation, and a description of the corrective action(s) that 

SDP took. 

63. Portable Flares. 

a. Applicability. The provisions of this Paragraph shall apply to Portable 

Flares. 

b. Distinction between Planned and Unplanned Outages of Covered Flares. 

For purposes of this Paragraph, a “planned” outage shall mean an outage of a Regular-Use 

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Covered Flare that is scheduled 30 days or more in advance of the outage. An “unplanned” 

outage is an outage of a Covered Flare that either is scheduled less than 30 days in advance or is 

unscheduled. 

c.	 504 hours or less. For any planned or unplanned outage of a Covered 

Flare that SDP knows or reasonably anticipates will result in 504 hours or less of downtime on a 

1095-day rolling sum period, rolled daily, SDP shall make good faith efforts to ensure that the 

Portable Flare that replaces the Covered Flare complies with all of the requirements of this 

Consent Decree that are applicable to the Covered Flare that the Portable Flare replaces. 

d.	 More than 504 hours. 

i.	 Planned. For any planned outage of a Regular-Use Covered Flare 

that SDP knows or reasonably can anticipate will last 504 hours or 

more on a 1095-day rolling sum period, rolled daily, SDP shall 

ensure that the Portable Flare complies with all of the requirements 

of this Consent Decree related to the Regular-Use Covered Flare 

that it replaces as of the date that the Portable Flare is In Operation 

and Capable of Receiving Waste, Supplemental, and/or Sweep 

Gas, except that, in lieu of having to comply with the applicable 

dynamically-calculated NHVcz-limit under Subparagraph 56.b or the 

355 BTU/scf static NHVcz-limit under Subparagraph 56.d, SDP shall 

operate the Portable Flare so that, except as provided in 

Paragraph 60.b, the Portable Flare’s NHVcz is greater than or equal 

to 325 BTU/scf: (i) on a three-hour rolling average, rolled every 

fifteen minutes if a gas chromatograph is used to calculate NHVcz; 

(ii) on a one-hour rolling average, rolled every five minutes if a 

Net Heating Value Analyzer is used to calculate NHVcz. SDP shall 

utilize Steps 3 and 6 in Appendix 1.3 to calculate NHVcz. 

ii.	 Unplanned. For any unplanned outage of a Covered Flare that, in 

advance of the outage, SDP cannot reasonably anticipate will last 

longer than 504 hours, SDP shall ensure that the Portable Flare 

complies with all of the requirements of this Consent Decree 

related to the Covered Flare that it replaces by no later than 30 

days after the date that SDP knows or reasonably should have 

known that the outage will last 504 hours or more, except that, in 

lieu of having to comply with the applicable 

dynamically-calculated NHVcz-limit under Subparagraph 56.b or the 

355 BTU/scf static NHVcz-limit under Subparagraph 56.d, SDP shall 

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operate the Portable Flare so that, except as provided in 

Paragraph 60.b, the Portable Flare’s NHVcz is greater than or equal 

to 325 BTU/scf: (i) on a three-hour rolling average, rolled every 

fifteen minutes if a gas chromatograph is used to calculate NHVcz; 

(ii) on a one-hour rolling average, rolled every five minutes if a 

Net Heating Value Analyzer is used to calculate NHVcz. SDP shall 

utilize Steps 3 and 6 in Appendix 1.3 to calculate NHVcz. 

iii.	 SDP shall calculate NHVcz using a Net Heating Value for hydrogen 

of 1212 BTU/scf if the Portable Flare is equipped with a gas 

chromatograph for calculating Net Heating Value. 

e. Recordkeeping. SDP shall keep records sufficient to document 

compliance with the requirements of this Paragraph any time it uses a Portable Flare. 

I.	 NSPS Subpart A, J, and Ja Applicability 

64.	 NSPS Subparts A, J, and Ja. 

a. NSPS Subparts A and J. As of the Date of Lodging, each SDP Refinery 

Covered Flare shall continue to be an “affected facility” within the meaning of Subparts A and J 

of 40 C.F.R. Part 60 and shall comply with all of the requirements of Subparts A and J, including 

but not limited to 40 C.F.R. §§ 60.104(a)(1) and 60.105(a)(4), by no later than the Date of 

Lodging and continuing until November 11, 2015. 

b. NSPS Subparts A and Ja. Each SDP Refinery Covered Flare shall be an 

“affected facility” within the meaning of Subparts A and Ja of 40 C.F.R. Part 60, and shall 

comply with all of the requirements of Subparts A and Ja on and after November 11, 2015. After 

November 11, 2015, Subpart J shall not apply to the SDP Refinery Covered Flares. 

J.	 Eliminating Fuel Gas Flow from the SDP Refinery to the SDP Chemical Plant 

Covered Flares 

65. SDP shall take all steps necessary to locate and eliminate all connections and/or 

operations which could allow Fuel Gas from the SDP Refinery to be routed to the SDP Chemical 

Plant Covered Flares in accordance with these requirements: 

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a.	 By no later than December 31, 2014, SDP shall physically remove piping 

and/or physically isolate piping with a welded blind where such piping 

potentially allows Fuel Gas to be routed to the Olefins II and Olefins III 

Flares during emergency situations; 

b.	 By no later than December 31, 2016, SDP shall permanently cease using 

the Butane Butylene Hydrotreater Unit to process any refinery streams and 

shall eliminate the possibility that Fuel Gas from such operations may be 

routed from the Butane Butylene Hydrotreater Unit to the Olefins Flares; 

and 

c.	 By no later than December 31, 2016, SDP shall discover and permanently 

eliminate all other potential connections and/or operations which could 

allow Fuel Gas to be routed to the SDP Chemical Plant Covered Flares. 

K.	 Incorporation of Consent Decree Requirements into Federally Enforceable Permits 

66. Permits Needed to Meet Compliance Obligations. If any compliance obligation 

under this Section V requires SDP to obtain a federal, state, or local permit or approval, SDP 

shall submit timely and complete applications and take all other actions necessary to obtain all 

such permits or approvals. SDP may seek relief under the provisions of Section XI of this 

Decree (Force Majeure) for any delay in the performance of any such obligation resulting from a 

failure to obtain, or a delay in obtaining, any permit or approval required to fulfill such 

obligation, if SDP has submitted timely and complete applications and has taken all other actions 

necessary to obtain all such permits or approvals. 

67. Permits to Ensure Survival of Consent Decree Limits and Standards after 

Termination of Consent Decree. 

a. Prior to termination of this Consent Decree, SDP shall submit complete 

applications to the appropriate permitting authorities in the State of Texas to incorporate the 

limits and standards listed in Subparagraph 67.b into non-Title V, federally enforceable permits 

that will survive termination of this Consent Decree. Prior to termination of this Consent 

Decree, SDP shall submit to the appropriate permitting authorities in the State of Texas, 

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appropriate applications, amendments and/or supplements to incorporate as “applicable 

requirements” the limits and standards listed in Subparagraph 67.b to ensure that these limits and 

standards survive termination of this Consent Decree. 

b. The limits and standards imposed by the following Paragraphs of this 

Consent Decree shall survive termination: 17–24, 26–29, 40, 47, 49, 50–51, 53–55, 56.b–d, 

57.b–c, 58.c–e, 59–62, 64–65. Nothing in this Paragraph shall prohibit SDP from seeking to 

incorporate Paragraph 25 in a permit that survives termination of this Decree. 

68. Modifications to Title V Operating Permits. Prior to termination of this Consent 

Decree, SDP shall submit complete applications to the appropriate permitting authorities in the 

State of Texas to modify, amend, or revise the Title V permit of each Covered Facility to 

incorporate the limits and standards identified in the preceding Paragraph into the Title V 

permits. The Parties agree that the incorporation of these emission limits and standards into 

Title V Permits shall be done in accordance with applicable state or local Title V rules. The 

Parties agree that the incorporation may be by “amendment” under 40 C.F.R. § 70.7(d) and 

analogous state Title V rules, where allowed by state law. 

VI. EMISSION CREDIT GENERATION 

69.	 Prohibitions. 

a. Definition. “CD Emissions Reductions” shall mean any NOx, SO2, H2S, 

PM, PMTOTAL, PM10, PM2.5, VOC, or CO emissions reductions that result from any projects 

conducted or controls used to comply with this Consent Decree. 

b.	 Prohibitions. 

i.	 SDP shall neither generate nor use any CD Emissions Reductions: 

as netting reductions; as emissions offsets; to apply for, obtain, 

trade, or sell any emission reduction credits; or in determining 

whether a project would result in a significant emissions increase 

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or significant net emissions increase in any PSD, major nonattainment, and/or minor New Source Review permit or permit 

proceeding. Baseline actual emissions during any 24-month period 

selected by SDP shall be adjusted downward to exclude any 

portion of the baseline emissions that would have been eliminated 

as CD Emissions Reductions had SDP been complying with this 

Consent Decree during that 24-month period; 

ii.	 Any CD Emissions Reductions that result from the Waste Gas 

minimization requirements of Paragraphs 30–37 may not be used 

as netting reductions, as emissions offsets, or in determining 

whether a project is “major” in any PSD, major non-attainment 

and/or minor New Source Review permit or permit proceeding 

even if those Reductions result in emissions lower than the 

allowable level under the flaring limitations in Paragraph 41. 

Baseline actual emissions during any 24-month period selected by 

SDP shall be adjusted downward to exclude any portion of the 

baseline emissions that would have been eliminated as Waste Gas 

minimization related CD Emissions Reductions as if SDP 

previously achieved the reductions during that 24-month period; 

iii.	 Except as provided in Subparagraph 70.b, SDP shall not apply for, 

obtain, trade, or sell any emission reduction credits that result from 

CD Emissions Reductions. 

70. Outside the Scope of the Prohibition. Nothing in this Section is intended to 

prohibit SDP from seeking to nor prohibit the State of Texas from denying SDP’s ability to: 

a.	 Use or generate netting reductions or emission reduction credits for 

refinery units that are not subject to an emission limitation pursuant to this 

Consent Decree; 

b.	 Use CD Emissions Reductions for the Covered Facilities’ compliance with 

any rules or regulations designed to address regional haze or the 

non-attainment status of any area (excluding PSD and Non-Attainment 

New Source Review rules, but including, for example, RACT rules) that 

apply to the Covered Facilities; provided, however, that SDP shall not be 

allowed to trade or sell any CD Emissions Reductions. 

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VII. MITIGATION PROJECTS
 

71. SDP shall undertake the “Mitigation Project: North Effluent Treater Controls” set 

forth in Appendix 2.6 of this Decree in accordance with the requirements of Appendix 2.6. 

72. SDP shall undertake the “Mitigation Project: Tank Controls” set forth in 

Appendix 2.7 of this Decree in accordance with the requirements of Appendix 2.7. 

73. SDP shall undertake the “Mitigation Project: ACU and BEU Controls” set forth 

in Appendix 2.8 of this Decree in accordance with the requirements of Appendix 2.8. 

74. By signing this Consent Decree, SDP certifies that it is not required to perform or 

develop these Mitigation Projects by any federal, state, or local law or regulation and is not 

required to perform or develop these Projects by agreement, grant, or as injunctive relief awarded 

in any other action in any forum; that these Projects are not ones that SDP was planning or 

intending to construct, perform, or implement other than in settlement of the claims resolved by 

this Decree; and that SDP will not receive any reimbursement for any portion of the costs of 

these Projects from any other person. 

75. Mitigation Project Progress and Completion Reports. SDP shall include in each 

report required under Paragraph 85, a status update on each Mitigation Project required by this 

Section. In addition, the report required by Paragraph 85 for the period in which the Project is 

completed shall contain the following information: 

a.	 A detailed description of the Project as implemented; 

b.	 A description of any problems encountered in completing the Project and 

the solutions thereto; 

c.	 A description of the environmental and public health benefits resulting 

from implementation of the Project (with a quantification of the benefits 

and an estimate of the pollutant reductions); and 

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d.	 A certification that the Project has been fully implemented pursuant to the 

provisions of this Decree. 

VIII. SUPPLEMENTAL ENVIRONMENTAL PROJECTS 

76. SDP shall implement as a Supplemental Environmental Project (“SEP”) a project 

to install and operate an open path air monitor on the fenceline of the Covered Facilities (“Fence 

Line Open Path Monitoring SEP”), in accordance with this Paragraph and the criteria, terms, and 

procedures in Appendix 2.9 of this Consent Decree. SDP shall spend not less than $1 million to 

implement this SEP. SDP shall undertake the tasks required for implementing the Fence Line 

Open Path Monitoring SEP in accordance with the schedule required by Appendix 2.9. 

77. SDP shall implement a SEP designed to reduce diesel emissions from school 

buses and/or non-school bus publicly owned vehicles in the vicinity of the Covered Facilities 

(“Diesel Retrofit SEP”) in accordance with this Paragraph and the criteria, terms and procedures 

in Appendix 2.10. SDP shall spend no less than $200,000 to implement this SEP. No SEP funds 

shall be used for testing or demonstration. SDP shall complete the implementation of the Diesel 

Retrofit SEP by no later than 24 months after the Date of Entry. 

78. With respect to the Diesel Retrofit SEP, SDP certifies under penalty of law that it 

would have agreed to perform a comparably valued, alternative project other than a diesel 

emissions reduction Supplemental Environmental Project if EPA were precluded by law from 

accepting a diesel emissions reduction Supplemental Environmental Project. 

79. SDP is responsible for the satisfactory completion of the Fence Line Monitoring 

SEP and the Diesel Retrofit SEP as provided in this Consent Decree. SDP may use contractors 

or consultants in planning and implementing the SEPs. 

a.	 If SDP completes the SEPs in accordance with all applicable requirements 

but does not expend the entire amount specified in Paragraphs 76 or 77, 

SDP shall pay the difference between the amount expended as 

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demonstrated in the certified cost report and the amount specified in 

Paragraphs 76 or 77 (as applicable). The difference shall be paid as 

provided in Section X of this Consent Decree. 

b.	 As an alternative to payment of such amount, SDP may request, and EPA 

may, in its sole discretion, approve use of the unexpended SEP funds for 

an alternative SEP. 

80. With regard to the Fence Line Open Path Monitoring and Diesel Retrofit SEPs, 

SDP certifies the truth and accuracy of each of the following: 

a.	 That all cost information provided to EPA in connection with EPA’s 

approval of these SEPs is complete and accurate and that SDP in good 

faith estimates that the cost to implement the Fence Line Open Path 

Monitoring SEP is $1 million and the cost to implement the Diesel 

Retrofit SEP is $200,000; 

b.	 That, as of the date of executing this Consent Decree, SDP is not required 

to perform or develop these SEPs by any federal, state, or local law or 

regulation and is not required to perform or develop these SEPs by 

agreement, grant, or as injunctive relief awarded in any other action in any 

forum; 

c.	 That these SEPs are not projects that SDP was planning or intending to 

construct, perform, or implement other than in settlement of the claims 

resolved in this Consent Decree; 

d.	 That SDP has not received and will not receive credit for the SEPs in any 

other enforcement action; 

e.	 That SDP will not receive any reimbursement for any portion of the SEPs 

from any other person; 

f.	 That SDP is not a party to any Open Federal Financial Assistance 

Transaction that is or could be used to fund the same activity as the SEPs; 

and 

g.	 That, to the best of SDP’s knowledge and belief based upon reasonable 

inquiry: 

i.	 There is no open Federal Financial Assistance Transaction that is 

funding or could fund the same activity as the SEPs; and 

ii.	 The activity covered by these SEPs has not been described in an 

unsuccessful Federal Financial Assistance Transaction proposal 

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submitted by SDP to EPA within two years of the date of 

executing this Consent Decree (unless the project was barred from 

funding as statutorily ineligible). 

81. SDP shall include in each report required by Paragraph 85 of Part IX (Reporting) 

a description of its progress toward implementing the SEP required by this Section. In addition, 

the report required by Paragraph 85 for the period in which the SEP is completed will contain the 

following information with respect to the SEP (“SEP Completion Report”): 

a.	 A detailed description of the SEP as implemented. For the Diesel Retrofit 

SEP, the description shall include, with respect to each retrofit, the 

following information: 

i.	 Vehicle owner with contact name and phone number; 

ii.	 Vehicle type (e.g., mass transit bus, school bus); 

iii.	 Model year; 

iv.	 Engine Manufacturer; 

v.	 Actual, or if not known, estimated or projected, annual miles or 

hours of operation; 

vi.	 Retrofit type (e.g., oxidation catalyst, particulate filter); 

vii.	 Retrofit cost per vehicle (separate out installation costs); 

viii.	 Actual, or if not known, estimated or projected, annual fuel usage 

(gal/yr); 

ix.	 Actual, or if not known, estimated or projected, annual emissions 

reductions (PM, HC, CO); 

x.	 Copy of invoices for purchase of control technology; 

xi.	 Name of the technology installed as identified on the EPA or 

CARB webpages: 

http://www.epa.gov/otaq/retrofit/verif-list.htm 

http://www.epa.gov/otaq/smartway/transport/whatsmartway/verified-technologies.htm#idle 

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http://www.arb.ca.gov/diesel/verdev/vt/cvt.htm 

b. A description of any problems encountered in completing the SEP and the 

solutions thereto; 

c. An itemized list of all eligible SEP costs expended; 

d. Certification that the SEP has been fully implemented pursuant to the 

provisions of this Decree; and 

e. A description of the environmental and public health benefits resulting 

from implementation of the SEP (with a quantification of the benefits and 

pollutant reductions, if feasible). 

EPA may require information in addition to that described in this Paragraph, in order to evaluate 

SDP’s SEP Completion Report. 

82. Disputes concerning the satisfactory performance of the Fence Line Monitoring 

and Diesel Retrofit SEPs and the amount of eligible SEP costs may be resolved under 

Section XII of this Decree (“Dispute Resolution”). No other disputes arising under this Section 

shall be subject to Dispute Resolution. 

83. Any public statement, oral or written, in print, film, or other media, made by SDP 

and referring to one and/or both of the SEPs under this Decree shall include the following 

language: “This project was undertaken in connection with the settlement of an enforcement 

action, United States v. Shell Oil Co., et al., taken on behalf of the EPA under the Clean Air 

Act.” 

84. For federal income tax purposes, SDP agrees that it will neither capitalize into 

inventory or basis nor deduct any costs or expenditures incurred in performing either the Fence 

Line Monitoring SEP or the Diesel Retrofit SEP. 

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IX. REPORTING REQUIREMENTS 

85. Semi-Annual Reports. On the dates and for the time periods set forth in 

Paragraph 88, SDP shall submit to EPA in the manner set forth in Section XVI (Notices) the 

following information: 

a.	 A progress report on the implementation of the requirements in Section V 

of this Decree (Compliance Requirements) at the Covered Facilities; 

b.	 A description of any problems anticipated with respect to meeting the 

requirements of Section V at the Covered Facilities; 

c.	 A description of the status of the Mitigation Projects in Section VII of this 

Decree (Mitigation Project); 

d.	 A description of the status of the SEPs in Section VIII of this Decree; 

e.	 Monitoring equipment/instrument downtime; override of Automatic 

Control System (“ASC”); exceedances of emission standards; and 

compliance with compressor availability requirements; as described in 

Paragraph 86; 

f.	 For the semi-annual report due on July 31 of each year, annual emissions 

data, as described in Paragraph 87; 

g.	 Any additional matters required by any other Paragraph of this Consent 

Decree to be submitted in the semi-annual report; and 

h.	 Any additional matters that SDP believes should be brought to the 

attention of EPA. 

86. Monitoring Instrument/Equipment Downtime; Override of ACS; and Emissions 

Exceedances. On and after the date of applicability of any work practice or standard, SDP shall 

provide a summary of the following, per Covered Flare per calendar quarter (hours shall be 

rounded to the nearest tenth): 

a.	 Monitoring Instrument/Equipment Downtime. The total number of hours 

of downtime of each monitoring instrument/equipment required pursuant 

to Paragraphs 18–20 and 22–24 expressed as both an absolute number and 

a percentage of time the Covered Flare that the instrument/equipment 

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monitors is In Operation and Capable of Receiving Sweep, Supplemental, 

and/or Waste Gas; 

b.	 Monitoring Instrument/Equipment Downtime. If the total number of 

hours of downtime of any monitoring instrument/equipment required 

pursuant to Paragraphs 18–20 and 22–24 exceeds 110 hours in any 

calendar quarter (for a Regular-Use Covered Flare) or 5% of the operating 

time (for a Temporary-Use Covered Flare or Portable Flare), an 

identification of the periods of downtime by date, time, cause (including 

Malfunction or maintenance), and, if the cause is asserted to be a 

Malfunction, the corrective action taken; 

c.	 Override of Automatic Control System. The total number of hours in 

which SDP manually overrode the ACS required in Paragraph 53, 

expressed both as an absolute number of hours and a percentage of time 

the Covered Flare was In Operation and Capable of Receiving Sweep, 

Supplemental, and/or Waste Gas; provided however, that for any hour 

identified, the report shall describe either or both of the following: (i) if 

the reason for the override was one of the exceptions identified in 

Paragraph 54, a statement of which exception; or (ii) if the total number of 

hours in which the ACS was overridden was less than 110 hours (for a 

Regular-Use Covered Flare) or less than 5% of the operating time (for a 

Temporary-Use Covered Flare) and was caused by one or more of the 

exceptions identified in Paragraph 60, a statement to that effect; 

d.	 Override of Automatic Control System. If the reason for the override was 

not one of the exceptions set forth in Paragraph 54 or if the total number 

of hours in which the ACS was overriden exceeds 110 hours in any 

calendar quarter (for a Regular-Use Covered Flare) or 5% of the operating 

time (for a Temporary-Use Covered Flare), an identification of the periods 

of override by the date, time, duration, reason for the override, and 

corrective actions taken; 

e.	 Inapplicability of Emissions Standards. The total number of hours, 

expressed as both an absolute number of hours and a percentage of time 

that the Covered Flare was In Operation, in which the requirements of 

Paragraphs 56–59 were not applicable because the only gas or gases being 

vented was/were Pilot Gas and/or Purge Gas; for purposes of 

Subparagraphs 86.f. and 86.g, all remaining hours shall be termed “Hours 

of Applicability”; 

f.	 Exceedances of Emissions Standards. During the Hours of Applicability, 

the total number of hours, expressed as both an absolute number of hours 

and a percentage of time the Covered Flare was In Operation, of 

exceedances of the emissions standards in Subparagraphs 56.b–d, 57.b, 

58.c–d, and 59; provided however, that if the exceedance of these 

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standards was less than 110 hours in the calendar quarter (for Regular-Use 

Covered Flares) or 5% of the total Hours of Applicability (for 

Temporary-Use Covered Flares) and was due to one or more of the 

exceptions set forth in Paragraph 60, the report shall so note; 

g.	 Exceedances of Emissions Standards. During the Hours of Applicability, 

if the exceedance of the emissions standards in Subparagraphs 56.b–d, 

57.b, 58.c–d, and 59 was not due to one of the exceptions in Paragraph 60, 

or if the exceedance was due to one or more of the exceptions in 

Paragraph 60 but the total number of hours caused by the exceptions in 

Paragraph 60 was greater than 110 (for Regular-Use Covered Flares) or 

5% of the total Hours of Applicability (for Temporary-Use Covered and 

Portable Flares), an identification of each block period that exceeded the 

standard, by time and date; the cause of the exceedance (including Startup, 

Shutdown, maintenance, or Malfunction), and if the cause is asserted to be 

a Malfunction, an explanation and any corrective actions taken; 

h.	 Flaring Limitations Exceedances. 

i.	 For any Waste Gas flows that are excluded from the calculation of 

flow rate because they are asserted to be based on one or more of 

the excludible events identified in Subparagraph 44.b, the 

information required in Subparagraph 44.c; 

ii.	 An identification of each calendar day in which the limitations on 

flaring set forth in Paragraph 41 were exceeded; 

iii.	 The cause of the exceedance; and 

iv.	 If the cause is asserted to be a Malfunction, an explanation and any 

corrective actions taken; 

i.	 Intentionally Left Blank; and 

j.	 Compliance with Compressor Availability Requirements. In each 

semi-annual report starting on and after July 31, 2015 (for the compressors 

within the FGRS systems at the SDP Refinery), and in each semi-annual 

report starting on and after January 31, 2019 (for the compressors within 

the Olefins FGRS), SDP shall provide sufficient information to document 

compliance with the Compressor availability requirements of 

Subparagraph 40.b (for the SDP Refinery FGRS Compressors) and 

Subparagraph 47.b (for SDP Olefins FGRS Compressors). For any period 

of non-compliance, SDP shall identify the date, cause, and corrective 

action taken. 

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87. Emissions Data. In the semi-annual report that is submitted on July 31 of each 

year, SDP shall provide, for each Covered Flare, for the prior calendar year, the amount of 

emissions of the following compounds (in tons per year): VOCs, SO2, H2S, CO2, methane, and 

ethane. 

88. Due Dates. The first compliance status report shall be due thirty-one days after 

the first full half-year after the Effective Date of this Consent Decree (i.e., either: (i) January 31 

of the year after the Effective Date, if the Effective Date is between January 1 and June 30 of the 

preceding year; or (ii) July 31 of the year after the Effective Date, if the Effective Date is 

between July 1 and December 31). The initial report shall cover the period between the 

Effective Date and the first full half year after the Effective Date (a “half year” runs between 

January 1 and June 30 and between July 1 and December 31). Until termination of this Decree, 

each subsequent report will be due on January 31 and July 31 and shall cover the prior half year 

(i.e., January 1 to June 30 or July 1 to December 31). Whenever this Consent Decree requires 

compliance within a certain number of “months” after a triggering event, the compliance 

obligation commences on the anniversary of the numerical date that triggers the obligation. For 

example, if compliance is required by no later than three months after the submission of a 

particular document, and if the document is submitted on March 23, 2012, the compliance 

obligation commences on June 23, 2012. 

89. Each report submitted under this Consent Decree shall be signed by the Covered 

Facilities’ Manager (or his/her designee), the person responsible for environmental management 

at the Covered Facilities, or by a person responsible for overseeing implementation of this 

Consent Decree across SDP, and shall include the following certification: 

I certify under penalty of law that this document and all attachments were 

prepared under my direction or supervision in accordance with a system designed 

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to assure that qualified personnel properly gather and evaluate the information 

submitted. Based on my inquiry of the person or persons who manage the system, 

or those persons directly responsible for gathering the information, the 

information submitted is, to the best of my knowledge and belief, true, accurate, 

and complete. 

90. The reporting requirements of this Consent Decree do not relieve SDP of any 

reporting obligations required by the CAA or implementing regulations, or by any other federal, 

state, or local law, regulation, permit, or other requirement. 

91. Any information provided pursuant to this Consent Decree may be used by the 

United States in any proceeding to enforce the provisions of this Consent Decree and as 

otherwise permitted by law. 

X. STIPULATED PENALTIES 

92. Failure to Pay Civil Penalty. If SDP fails to pay any portion of the civil penalty 

required to be paid under Section IV of this Decree (Civil Penalty) when due, SDP shall pay a 

stipulated penalty of $2500 per day for each day that the payment is late. Late payment of the 

civil penalty and any accrued stipulated penalties shall be made in accordance with 

Paragraph 13. 

93. Failure to Meet all Other Consent Decree Obligations. SDP shall be liable for 

stipulated penalties to the United States for violations of this Consent Decree as specified below 

unless excused under Section XI of this Decree (Force Majeure). For those provisions where a 

stipulated penalty of either a fixed amount or 1.2 times the economic benefit of delayed 

compliance is available, the decision of which alternative to seek rests exclusively within the 

discretion of the United States. For a given calendar day, where a failure to comply with the 

30-day and/or the 365-day rolling average limit on Waste Gas flaring at the SDP Refinery 

required by Subparagraph 41.a of this Decree (and potentially subject to the stipulated penalty 

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provisions of Subparagraphs 93.l and/or 93.m) is the result of a failure to have the requisite 

number of Compressors Available for Operation as required by Subparagraph 40.b of this Decree 

(and potentially subject to the stipulated penalty provisions of Subparagraphs 93.j and/or 93.k), 

only the stipulated penalty provision that results in the higher penalty shall be applicable for that 

calendar day (i.e., stipulated penalties under both Subparagraph 93.l and/or 93.m and 

Subparagraph 93.j and/or 93.k shall not be assessed). Nothing in the previous sentence shall be 

construed to result in only one penalty being applicable on any given calendar day for violations 

of both the 30-day and the 365-day rolling average limits on Waste Gas flaring (i.e., for any 

given calendar day in which both the 30-day and 365-day rolling average limits are violated, 

stipulated penalties under both Subparagraph 93.l. and 93.m may be assessed). 

Violation Stipulated Penalty 

93.a. Violation of Paragraph 16. 

Failure to timely submit a report (¶ 16) 

that conforms to the requirements of that 

Paragraph 

Period of delay or 

noncompliance 

Days 1–30 

Days 31–60 

Days 61 and later 

Penalty per day 

$ 300 

$ 400 

$ 500 

93.b. Violation of Paragraph 30, 31, or 

32. Failure to timely submit a plan 

(¶¶ 30, 31, or 32) that conforms to the 

requirements of the respective 

Paragraph 

Period of delay or 

noncompliance 

Days 1–30 

Days 31–60 

Days 61 and later 

Penalty per day 

$ 500 

$ 750 

$ 1000 

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93.c. Violation of Paragraph 17, 18, 19, 

20, 21, 22, 23, 24, 26, or 27. Failure to 

timely install the equipment and 

monitoring systems required by 

Paragraphs 18–24 in accordance with 

the respective, applicable technical 

specifications in those Paragraphs, 

Paragraphs 26–27, and Appendix 1.10 

(except for the requirements of 

Appendix 1.10 found in Subparagraphs 

I.g, III.e, IV, V.B, or VII.a: those are 

QA/QC requirements covered in 

Subparagraph 93.d below) 

Period of delay or

noncompliance, 

per monitoring system 

Days 1–30 

Days 31–60 

Days 61 and later 

 Penalty per day 

 per monitoring 

system 

$ 750 

$ 1250 

$ 2000 or an amount 

equal to 1.2 times 

the economic 

benefit of delayed 

compliance, 

whichever is greater 

93.d. Violation of the QA/QC 

requirements in Appendix 1.10. Failure 

to comply with the QA/QC 

requirements in Appendix 1.10 at 

Subparagraphs I.g, III.e, IV, V.B, and 

VII.a 

Violation of a: 

Daily requirement

Quarterly requirement

Annual requirement

Penalty 

$ 100 

 $ 200 per day late 

 $ 500 per day late 

93.e Violation of Paragraph 28: Per monitoring system, Penalty per hour 

Regular-Use Covered Flares. After the number of hours per per monitoring 

dates in Column H of Appendix 2.1, calendar quarter of system 

except for 110 hours per calendar downtime over 110 

quarter, failure to operate the monitoring 

systems in Paragraphs 18–20 and 22– 0.25–50.0 $ 250 

24; provided however, that SDP shall 50.25–100.0 $ 500 

not be liable for a stipulated penalty for Over 100.0 $ 1000 

violation of Paragraph 28 if, during the 

period of instrument downtime, the only 

gas(es) being sent to the Regular-Use 

Covered Flare in question is/are Purge 

Gas and/or Pilot Gas. For any 

monitoring system that serves a dual 

purpose, this stipulated penalty applies 

per instrument only. 

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93.f. Violation of Paragraph 28: 

Temporary-Use Covered Flares. After 

the dates in Column H of Appendix 2.1, 

except for 5% per uninterrupted period 

of time that a Temporary-Use Covered 

Flare is In Operation and Capable of 

Receiving Sweep, Supplemental, and/or 

Waste Gas, failure to operate the 

monitoring systems in Paragraphs 18–20 

and 22–24; provided however, that SDP 

shall not be liable for a stipulated 

penalty for violation of Paragraph 28 if, 

during the period of instrument 

downtime, the only gas(es) being sent to 

the Temporary-Use Covered Flare in 

question is/are Purge Gas and/or Pilot 

Gas. For any monitoring system that 

serves a dual purpose, this stipulated 

penalty applies per instrument only. 

Per monitoring system, 

number of hours per

uninterrupted period 

of time 

0.25–50.0 

50.25–100.0 

Over 100.0 

Penalty per hour 

 per monitoring 

system 

$ 250 

$ 500 

$ 1000 

93.g. Violation of Paragraph 35. Period of delay or Penalty per day 

Failure to timely develop a report that noncompliance 

conforms to the requirements in 

Subparagraph 35.a; or failure to keep it Days 1 – 30 $ 800 

as an internal record; or failure to timely Days 31 – 60 $ 1,600 

submit a summary of the flaring incident Days 61 and later $ 3,000 

reports that conforms to the 

requirements in Subparagraph 35.b 

93.h. Violation of Paragraph 36. Period of delay or Penalty per day 

Failure to complete any corrective noncompliance 

action under Paragraph 36 in accordance 

with the schedule for corrective action Days 1 – 30 $ 1,000 

agreed to by SDP or imposed on SDP Days 31 – 60 $ 2,000 

pursuant to the dispute resolution Days 61 and later $ 5,000 

provisions of this Decree (with any such 

extensions thereto as to which EPA and 

SDP may agree in writing) 

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93.i. Violation of Paragraph 39 or 

Paragraph 45. Failure to timely install, 

in accordance with Paragraph 39 or 

Paragraph 45 (as applicable), a Flare 

Gas Recovery System that conforms to 

the requirements of Paragraph 39 or 

Paragraph 45(as applicable) 

Period of delay or Penalty per day per FGRS 

noncompliance, per FGRS 

Days 1–30 $ 1250 

Days 31–60 $ 3000 

Days 61 and later $ 5000 or an amount 

equal to 1.2 times 

the economic 

benefit of delayed 

compliance, 

whichever is greater 

93.j. Violation of Certain Subparagraph 

40.b.ii or Subparagraph 47.b.ii 

requirements. For each failure to 

comply with the Subparagraph 40.b.ii 

requirement to have four Compressors 

Available for Operation and/or in 

operation “at all times,” or for each 

failure to comply with the Subparagraph 

47.b.ii requirement to have “n-2” 

Compressors Available for Operation 

and/or in operation “at all times” 

Per FGRS, per hour or fraction thereof: $750; provided 

however, that stipulated penalties shall not apply for any 

hour in which a Compressor’s unavailability did not 

result in flaring 

93.k. Violation of Certain 

Subparagraph 40.b or Subparagraph 

47.b Requirements (excluding those 

identified in Subparagraph 93.j). For 

each failure to comply with the 

following requirements in 

Subparagraph 40.b. or 

Subparagraph 47.b: 

(1) Subparagraph 40.b.i or 

Subparagraph 47.b.i requirement to have 

one Compressor Available for Operation 

and/or in operation 98% of the time; 

(2) Subparagraph 40.b.i or 

Subparagraph 47.b.i requirement to have 

two Compressors Available for 

Operation and/or in operation 90% of 

the time; 

(3) Subparagraph 40.b.ii or 

Subparagraph 47.b.ii requirement to 

have five Compressors or “n-1” 

Compressors, respectively, Available for 

Operation and/or in operation 95% of 

the time 

Per FGRS, the number of hours or fraction thereof–over 

the allowed percentage—in a rolling 8760-hour period 

that a Compressor required to be Available for Operation 

is not: $750; provided however, that stipulated penalties 

shall not apply for any hour or fraction thereof in which a 

Compressor’s unavailability did not result in flaring. 

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93.l. Violation of Paragraph 41.a.i 

Failure to comply with the 30-day 

rolling average limit on Waste Gas 

flaring at the SDP Refinery 

Pollutant Penalty per Day per ton 

SO2 $ 100 

VOC $ 300 

The amount of excess emissions during the event(s) 

which precipitate(s) the exceedance(s) of the 30-day 

rolling average limit is not the sole basis for calculating 

the stipulated penalty due. Instead, each day on which 

the 30-day rolling average limit is violated —which 

violations most likely continue even though the 

precipitating event and the excess emissions do not — 

counts as a separate day. SDP shall comply with 

Appendix 1.13 to calculate the stipulated penalties 

resulting from violating the flaring limitation in 

Paragraph 41.a.i. 

93.m. Violation of Paragraph 41.a.ii. 

Failure to comply with the refinery-wide 

365-day rolling average limit on Waste 

Gas flaring at the SDP Refinery 

Pollutant Penalty per Day per ton 

SO2 $ 40 

VOC $ 120 

The amount of excess emissions during the event(s) 

which precipitate(s) the exceedance(s) of the 365-day 

rolling average limit is not the sole basis for calculating 

the stipulated penalty due. Instead, each day on which 

the 365-day rolling average limit is violated—which 

violations most likely continue even though the 

precipitating event and the excess emissions do not— 

counts as a separate day. SDP shall comply with 

Appendix 1.13 to calculate the stipulated penalties 

resulting from violating the flaring limitation in 

Paragraph 41.a.ii. 

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93.n. Violation of Paragraph 48. 

Failure to timely convert the A&S Flare 

to Temporary-Use in conformance with 

the requirements of Paragraph 48. 

Period of delay or Penalty per day 

noncompliance 

Days 1–30 $ 1000 

Days 31–60 $ 2500 

Days 61 and later $ 5000 

93.o. Violation of Paragraph 49. 

Failure to comply with the 365-day 

rolling sum emission limit on VOCs 

from the HIPA Flare 

$2500 per calendar day on which the limit is exceeded 

93.p. Violation of Paragraph 53. 

Failure to timely install and operate, by 

the dates in Column G of Appendix 2.1, 

the Automatic Control System 

requirements of Paragraph 53 

Penalty per Covered Flare per day: $500 

93.q. Violation of Subparagraph 56.b, 

56.c, or 56.d. For each Covered Flare, 

failure to comply with the Net Heating 

Value in the Combustion Zone Gas 

(“NHVcz”) standard in Subparagraph 

56.b, 56.c, or 56.d. 

On a per Covered Flare Penalty per hour, 

basis, hours per calendar or fraction there of 

quarter in noncompliance per flare 

Hours 0.25–50.0 $ 25 

Hours 50.25–100.0 $ 75 

Hours over 100.0 $ 150 

For purposes of calculating the number of hours of 

noncompliance with the NHVcz standard, all 15-minute 

periods of violation shall be added together to determine 

the total. 

93.r. Violation of Subparagraph 57.a. Penalty per Covered Flare per day or fraction thereof: 

Between the Date of Lodging and the $1500 

compliance dates in Column H of 

Appendix 2.1, failure to use best efforts 

to maintain the S/VG ratio at each 

Covered Flare below 3.0; provided, 

however, that SDP shall not be liable for 

a stipulated penalty for violation of 

Subparagraph 57.a if, at the Covered 

Flare in question, SDP can demonstrate 

that it is complying with the 

requirements of Subparagraphs 56.b, 

56.c, or 56.d (as applicable) during the 

period of applicability of this stipulated 

penalty. 

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93.s. Violation of Subparagraph 58.c. 

Failure to comply with the prohibition 

on Discontinuous Wake Dominated 

Flow 

Flare Tip Size (inches) Penalty per hour or 

fraction thereof 

1.0–24.0 $ 150 

24.1–48.0 $ 225 

Over 48.0 $ 525 

93.t. Violation of Subparagraph 58.d. 

Failure to comply with the applicable 

MFR standard 

Flare Tip Size (inches) Penalty per hour or 

fraction thereof 

1.0–24.0 $ 50 

24.1–48.0 $ 75 

Over 48.0 $ 175 

For purposes of calculating the number of hours of 

noncompliance with the MFR limit, all 5-minute periods 

of violation shall be added together to determine the total. 

93.u. Violation of Paragraph 62. $100 per day 

Failure to record any information 

required to be recorded pursuant to 

Subparagraphs 62.a, b, c, or d 

93.v. Violation of Subparagraphs 63.d.i 

or 63.d.ii. Failure to ensure that a 

Portable Flare that falls under the 

conditions of Subparagraph 63.d.i or 

63.d.ii complies with the requirements 

of those Subparagraphs 

Number of days Penalty per day 

Portable Flare 

did not comply 

Days 1–7 $ 1000 

Days 8–15 $ 2000 

Days 16 and later $ 5000 

93.w. Violation of Paragraph 64. 

Failure to comply with the H2S emission 

limit at a Refinery Covered Flare after 

that Refinery Covered Flare is required 

to comply with 40 C.F.R. Part 60, 

Subpart J, or 40 C.F.R. Part 60, Subpart 

Ja 

On a per Covered Flare Penalty per hour per 

basis, hours (on a three- Covered Flare 

hour rolling average 

basis) per calendar quarter 

in noncompliance 

Hours 1–50.0 $ 50 

Hours 51–100.0 $ 100 

Hours over 100.0 $ 200 

For purposes of calculating the number of hours of 

noncompliance with the H2S limit, all one-hour periods 

of violation shall be added together to determine the total. 

The averaging period for this standard is a three-hour 

rolling average. 

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93.x. Violation of Paragraph 65. 

Failure to timely comply with the 

requirements of Paragraph 65 

Period of delay 

Days 1 – 30 

Days 31 – 60 

Days 61 and later 

Penalty per day 

$ 1,000 

$ 2,000 

$ 5,000 

93.y. Violation of Paragraphs 71–73, 

and Appendices 2.6–2.8. For failure to 

comply with any requirement of 

Paragraphs 71–73 or Appendices 2.6– 

2.8 

Period of delay or 

noncompliance 

Days 1–30 

Days 31–60 

Days 61 and later 

Penalty per day 

$ 500 

$ 1500 

$ 3000 

93.z. Violation of Paragraphs 76–77 

and Appendices 2.9–2.10. For failure to 

comply with any requirement of 

Paragraphs 76–77 and Appendices 2.9– 

2.10 

Period of delay or 

noncompliance 

Days 1–30 

Days 31–60 

Days 61 and later 

Penalty per day 

$ 500 

$ 1500 

$ 3000 

93.aa. Violation of Section IX 

(Reports). For each failure to submit 

reports as required by Section IX 

Period of delay or 

noncompliance 

per report 

Days 1–30 

Days 31–60 

Days 61 and later 

Penalty per day 

per report 

$ 300 

$ 1000 

$ 2000 

94. Waiver of Payment. The United States may, in its unreviewable discretion, 

reduce or waive payment of stipulated penalties otherwise due to it under this Consent Decree. 

95. Demand for Stipulated Penalties. A written demand by the United States for the 

payment of stipulated penalties will identify the particular violation(s) to which the stipulated 

penalty relates; the stipulated penalty amount (as can be best estimated) that the United States is 

demanding for each violation; the calculation method underlying the demand; and the grounds 

upon which the demand is based. Prior to issuing a written demand for stipulated penalties, the 

United States may, in its unreviewable discretion, contact SDP for informal discussion of matters 

that the United States believes may merit stipulated penalties. 

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96. Stipulated Penalties Accrual. Stipulated penalties will begin to accrue on the day 

after performance is due or the day a violation occurs, whichever is applicable, and, except as 

provided in Paragraph 99, shall continue to accrue until performance is satisfactorily completed 

or the violation ceases. Stipulated penalties shall accrue simultaneously for separate violations 

of this Consent Decree. 

97. Stipulated Penalties Payment Due Date. Stipulated penalties shall be paid no later 

than sixty (60) days after receipt of a written demand by the United States unless the demand is 

disputed through compliance with the requirements of the dispute resolution provisions of this 

Decree. 

98. Manner of Payment of Stipulated Penalties. Stipulated penalties owing to the 

United States of under $10,000 shall be paid by check and made payable to the “U.S. 

Department of Justice,” referencing DOJ Number 90-5-2-1-09388/1 and USAO File Number 

2012VO1637, and delivered to the U.S. Attorney’s Office in the Southern District of Texas, 

1000 Louisiana St., Suite 2300, Houston, TX 77002. Stipulated penalties owing to the United 

States of $10,000 or more shall be paid in the manner set forth in Section IV of this Decree (Civil 

Penalty). All transmittal correspondence shall state that the payment is for stipulated penalties, 

shall identify the violations to which the payment relates, and shall include the same identifying 

information required by Paragraph 13. 

99. Disputes over Stipulated Penalties. By no later than 60 days after receiving a 

demand for stipulated penalties, SDP may dispute liability for any or all stipulated penalties 

demanded by invoking the dispute resolution procedures of Section XII of this Decree (Dispute 

Resolution). In the event of a dispute over stipulated penalties, stipulated penalties shall not 

accrue commencing on the later of either: (i) the date that, during dispute resolution under 

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Section XII, the United States and SDP agree upon; or (ii) the date that SDP files a motion with 

the Court under Paragraph 113; provided however, that in order for stipulated penalties to cease 

accruing pursuant to either (i) or (ii), SDP must place the disputed amount in an interest-bearing 

commercial escrow account. If the dispute thereafter is resolved in SDP’s favor, the escrowed 

amount plus accrued interest will be returned to SDP; otherwise, the United States will be 

entitled to the amount determined by the Court to be due, plus interest that has accrued on such 

amount in the escrow account. 

100. No amount of the stipulated penalties paid by SDP shall be used to reduce its 

federal tax obligations. 

101. Subject to the provisions of Section XIV of this Decree (Effect of 

Settlement/Reservation of Rights), the stipulated penalties provided for in this Decree shall be in 

addition to any other rights, remedies, or sanctions available to the United States for a violation 

of this Consent Decree or applicable law. In addition to injunctive relief or stipulated penalties, 

the United States may seek mitigating emissions reductions equal to or greater than the excess 

amounts emitted if the violations result in excess emissions. SDP reserves the right to oppose 

the United States’ request for mitigating emission reductions. SDP shall be allowed a credit, for 

any stipulated penalties paid, against any statutory penalties imposed for such violation. 

XI. FORCE MAJEURE 

102. “Force Majeure,” for purposes of this Consent Decree, is defined as any event 

beyond the control of SDP, its contractors, or any entity controlled by SDP that delays the 

performance of any obligation under this Consent Decree despite SDP’s best efforts to fulfill the 

obligation. The requirement that SDP exercise “best efforts to fulfill the obligation” includes 

using best efforts to anticipate any potential Force Majeure event and best efforts to address the 

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effects of any such event: (a) as it is occurring; and (b) after it has occurred, to prevent or 

minimize any resulting delay. 

103. “Force Majeure” does not include SDP’s financial inability to perform any 

obligation under this Consent Decree. Unanticipated or increased costs or expenses associated 

with the performance of SDP’s obligations under this Consent Decree shall not constitute 

circumstances beyond SDP’s control nor serve as the basis for an extension of time under this 

Section XI. 

104. If any event occurs or has occurred that may delay the performance of any 

obligation under this Consent Decree, whether or not caused by a Force Majeure event, SDP 

shall notify EPA in writing not later than fifteen calendar days after the time SDP first knew or 

should have known by the exercise of due diligence that the event might cause a delay. In the 

written notice, SDP shall specifically reference this Paragraph 104 of the Consent Decree and 

shall provide an explanation and description of the reasons for the delay; the anticipated duration 

of the delay; all actions taken or to be taken to prevent or minimize the delay; a schedule for 

implementation of any measures to be taken to prevent or mitigate the delay or the effect of the 

delay; SDP’s rationale for attributing such delay to a Force Majeure event if it intends to assert 

such a claim; and a statement as to whether, in the opinion of SDP, such event may cause or 

contribute to an endangerment to public health, welfare, or the environment. SDP shall be 

deemed to know of any circumstance of which SDP, any entity controlled by SDP, or SDP’s 

contractors knew or should have known. SDP shall include with any notice all available 

documentation supporting the claim that the delay was attributable to a Force Majeure. The 

written notice required by this Paragraph shall be effective upon the mailing of the same by 

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overnight mail or by certified mail, return receipt requested, to EPA in the manner set forth in 

Section XVI of this Decree (Notices). 

105. Failure by SDP to comply with the requirements in Paragraph 104 shall preclude 

SDP from asserting any claim of Force Majeure for the event for the period of time of such 

failure to comply, and for any additional delay caused by such failure. 

106. If EPA agrees that the delay or anticipated delay is attributable to a Force Majeure 

event, the time for performance of the obligations under this Consent Decree that are affected by 

the Force Majeure event will be extended by EPA for such time as is necessary to complete those 

obligations. An extension of the time for performance of the obligations affected by the Force 

Majeure event shall not, of itself, extend the time for performance of any other obligation. EPA 

will notify SDP in writing of the length of the extension, if any, for performance of the 

obligations affected by the Force Majeure event. 

107. If EPA does not agree that the delay or anticipated delay has been or will be 

caused by a Force Majeure event, or if the EPA and SDP fail to agree on the length of the delay 

attributable to the Force Majeure event, EPA will notify SDP of its decision. 

108. If SDP elects to invoke the dispute resolution procedures set forth in Section XII 

of this Decree (Dispute Resolution), it shall do so no later than 45 days after receipt of EPA’s 

notice. In any such proceeding, SDP shall have the burden of demonstrating by a preponderance 

of the evidence that the delay or anticipated delay has been or will be caused by a Force Majeure 

event, that the duration of the delay or the extension sought was or will be warranted under the 

circumstances, that best efforts were exercised to avoid and mitigate the effects of the delay, and 

that SDP complied with the requirements of Paragraphs 102 and 104. If SDP carries this burden, 

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the delay at issue shall be deemed not to be a violation by SDP of the affected obligation of this 

Consent Decree identified to EPA and the Court. 

XII. DISPUTE RESOLUTION 

109. Unless otherwise expressly provided for in this Consent Decree, the dispute 

resolution procedures of this Section shall be the exclusive mechanism to resolve disputes arising 

under or with respect to this Consent Decree. 

A. For All Disputes Except those Arising Under Subparagraphs 43.c and 46.c 

110. Informal Dispute Resolution. The first stage of dispute resolution shall consist of 

informal negotiations. The dispute shall be considered to have arisen when one Party sends the 

other Party a written Notice of Dispute. Such Notice of Dispute shall state clearly the matter in 

dispute. The period of informal negotiations shall not exceed 60 days after the Notice of 

Dispute, unless that period is modified by written agreement. If the Parties cannot resolve the 

dispute by informal negotiations, then the position advanced by the United States shall be 

considered binding unless within 45 days after the conclusion of the informal negotiation period, 

SDP invokes formal dispute resolution procedures set forth below. 

111. Formal Dispute Resolution. SDP shall invoke formal dispute resolution 

procedures, within the time period provided in the preceding Paragraph, by serving on the United 

States a written Statement of Position regarding the matter in dispute. The Statement of Position 

shall include, but need not be limited to, any factual data, analysis, or opinion supporting SDP’s 

position and any supporting documentation relied upon by SDP. 

112. The United States shall serve its Statement of Position within 45 days of receipt 

of SDP’s Statement of Position. The United States’ Statement of Position shall include, but need 

not be limited to, any factual data, analysis, or opinion supporting that position and any 

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supporting documentation relied upon by the United States. The United States’ Statement of 

Position shall be binding on SDP unless SDP files a motion for judicial review of the dispute in 

accordance with the following Paragraph. 

113. SDP may seek judicial review of the dispute by filing with the Court and serving, 

in accordance with Section XVI of this Decree (Notices), on the United States a motion 

requesting judicial resolution of the dispute. The motion must be filed within 45 days of receipt 

of the United States’ Statement of Position pursuant to the preceding Paragraph. The motion 

shall contain a written statement of SDP’s position on the matter in dispute, including any 

supporting factual data, analysis, opinion, or documentation, and shall set forth the relief 

requested and any schedule within which the dispute must be resolved for orderly 

implementation of the Consent Decree. 

114. The United States shall respond to SDP’s motion within the time period allowed 

by the Local Rules of this Court for responses to dispositive motions. SDP may file a reply 

memorandum, to the extent permitted by the Local Rules. 

115. In a formal dispute resolution proceeding under this Section, SDP shall bear the 

burden of demonstrating that its position complies with this Consent Decree and the CAA and 

that it is entitled to relief under applicable principles of law. The United States reserves the right 

to argue that its position is reviewable only on the administrative record and must be upheld 

unless arbitrary and capricious or otherwise not in accordance with law, and SDP reserves the 

right to argue to the contrary. 

116. The invocation of dispute resolution procedures under this Section shall not, by 

itself, extend, postpone, or affect in any way any obligation of SDP under this Consent Decree, 

unless and until final resolution of the dispute so provides. Stipulated penalties with respect to 

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the disputed matter shall accrue in accordance with Paragraph 99, but payment shall be stayed 

pending resolution of the dispute. 

B. For Disputes Arising Under Subparagraphs 43.c and 46.c 

117. For disputes arising under Subparagraphs 43.c and/or 46.c, the provisions of this 

Subsection XII.B shall apply if SDP invokes the accelerated dispute resolution as allowed by 

Subparagraphs 43.c or 46.c. Paragraphs 110-116 are incorporated herein by reference except for 

the following changes: 

Reference Instead Of Use 

Para. 110; 4th Sentence 60 days 15 days 

Para. 110; 5th Sentence 45 days 10 days 

Para. 112; 1st Sentence 45 days 15 days 

Para. 113; 2nd Sentence 45 days 15 days 

Para. 114; 1st Sentence 

“within the time 

period allowed by the 

Local Rules of this 

Court for responses to 

dispositive motions” 

“within 21 days” 

118. If a dispute under Subparagraphs 43.c or 46.c comes before this Court for 

disposition, both Parties jointly shall advise the Court that time is of the essence. 

XIII. INFORMATION COLLECTION AND RETENTION 

119. The United States and its representatives, employees, contractors, and consultants 

shall have the right of entry into the Covered Facilities, at all reasonable times, upon 

presentation of credentials and any other documentation required by law, to: 

a. monitor the progress of activities required under this Consent Decree; 

b. verify any data or information submitted to the United States in 

accordance with the terms of this Consent Decree; 

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c.	 obtain documentary evidence, including photographs and similar data, 

relevant to compliance with the terms of this Consent Decree; and 

d.	 assess SDP’s compliance with this Consent Decree. 

120. Except for data recorded by any video camera that may be required pursuant to 

Paragraph 24, until one year after termination of this Consent Decree, SDP shall retain all 

documents, records, or other information, regardless of storage medium (e.g., paper or 

electronic) in its possession or control that directly relate to SDP’s performance of its obligations 

under this Consent Decree. Except for data recorded by any video camera that may be required 

pursuant to Paragraph 24, until one year after termination of this Consent Decree, SDP shall 

instruct its contractors and agents to preserve all documents, records, or other information, 

regardless of storage medium (e.g., paper or electronic) in its contractors’ or agents’ possession 

or control, or that come into its or its contractors’ or agents’ possession or control, that 

demonstrate or document SDP’s compliance or non-compliance with the obligations of this 

Consent Decree. This information-retention requirement shall apply regardless of any contrary 

corporate or institutional policies or procedures. At any time during this information-retention 

period, the United States may request copies of any documents, records, or other information 

required to be maintained under this Paragraph. SDP shall retain the data recorded by any video 

camera required pursuant to Paragraph 24 for six months from the date of recording except that 

SDP shall keep any such video record until one year after termination if SDP was required to 

keep the record pursuant to Subparagraph 62.c. 

121. Except for emissions data, SDP may assert that information required to be 

provided under this Section is protected as Confidential Business Information (“CBI”) under 

40 C.F.R. Part 2. As to any information that SDP seeks to protect as CBI, SDP shall follow the 

procedures set forth in 40 C.F.R. Part 2, where applicable. 

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122. This Consent Decree in no way limits or affects any right of entry and inspection, 

or any right to obtain information, held by the United States pursuant to applicable federal laws, 

regulations, or permits, nor does it limit or affect any duty or obligation of SDP to maintain 

documents, records, or other information imposed by applicable federal or state laws, 

regulations, or permits. 

XIV. EFFECT OF SETTLEMENT/RESERVATION OF RIGHTS 

123. Definitions. For purposes of this Section XIV, the following definitions apply: 

a.	 “BTU/scf Flared Gas Requirements” shall mean the requirements found in 

the following regulations: 

i.	 40 C.F.R. § 60.18(c)(3)(ii); 

ii.	 40 C.F.R. § 63.11(b)(6)(ii); 

iii.	 40 C.F.R. §§ 60.482-10(d), 60.482-10a(d), but only to the extent 

that these provisions require compliance with 40 C.F.R. 

§ 60.18(c)(3)(ii); 

iv.	 40 C.F.R. §§ 60.592(a), 60.592a(a), but only to the extent that 

these provisions: (1) relate to flares; and (2) require compliance 

with 40 C.F.R. § 60.18(c)(3)(ii); 

v.	 40 C.F.R. § 63.643(a)(1), but only to the extent that this provision 

requires compliance with 40 C.F.R. § 63.11(b)(6)(ii); 

vi.	 40 C.F.R. § 63.648(a), but only to the extent that this provision: 

(1) relates to flares; and (2) requires compliance with 40 C.F.R. 

§ 60.18(c)(3)(ii); 

vii.	 40 C.F.R. § 61.349(a)(2)(iii), but only to the extent that this 

provision requires compliance with 40 C.F.R. § 60.18(c)(3)(ii); 

viii.	 40 C.F.R. § 63.1566(a)(1)(i) and Table 15, but only to the extent 

that these provisions: (1) relate to flares; and (2) require 

compliance with 40 C.F.R. § 63.11(b)(6)(ii); and 

ix.	 40 C.F.R. § 63.113(a)(1)(i), but only to the extent that this 

provision requires compliance with 40 C.F.R. § 63.11(b)(6)(ii). 

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b. “General Flare Requirements” shall mean the requirements found in the 

following regulations: 

i. 40 C.F.R. § 60.18(c)(1) and 

40 C.F.R. § 63.11(b)(4) 

(both relate to a prohibition on visible emissions); 

ii. 40 C.F.R. § 60.18(c)(2) and 

40 C.F.R. § 63.11(b)(5) 

(both relate to flame presence); 

iii. 40 C.F.R. § 60.18(c)(4) and 

40 C.F.R. § 63.11(b)(7) 

(both relate to exit velocity requirements for steam-assisted flares); 

and 

iv. 40 C.F.R. § 60.18(e) and 

40 C.F.R. § 63.11(b)(3) 

(both relate to operation during emissions venting). 

c. “Good Air Pollution Control Practice Requirements” shall mean the 

requirements found in the following regulations: 

i. 40 C.F.R. § 60.11(d); 

ii. 40 C.F.R. § 61.12(c); 

iii. 40 C.F.R. § 63.6(e)(1)(i); 

iv. 40 C.F.R. Part 63, Subpart CC, Table 6, but only to the extent that 

Table 6 requires compliance with 40 C.F.R. § 63.6(e)(1)(i); and 

v. 40 C.F.R. Part 63, Subpart UUU, Table 44, but only to the extent 

that Table 44 requires compliance with 40 C.F.R. § 63.6(e)(1). 

d. “Post-Lodging Compliance Dates” shall mean any dates in this 

Section XIV after the Date of Lodging; 

e. “PSD/NNSR Requirements” shall mean the Prevention of Significant 

Deterioration and Non-Attainment New Source Review requirements 

found in the following: 

i. 42 U.S.C. § 7475; 

ii. 40 C.F.R. §§ 52.21(a)(2)(iii) and 52.21(j)–52.21(r)(5); 

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iii.	 42 U.S.C. §§ 7502(c)(5), 7503(a)–(c); 

iv.	 40 C.F.R. Part 51, Appendix S, Part IV, Conditions 1–4; 

v.	 any applicable, federally enforceable state or local regulation that 

implements, adopts, or incorporates the federal provisions cited in 

Subparagraphs 123.e.i–iv; and 

vi.	 Title V permit requirement that implements, adopts, or 

incorporates the federal, or federally enforceable state, provisions 

cited in Subparagraphs 123.e.i–v; 

f.	 “Requirements Related to Monitoring, Operation, and Maintenance 

According to Flare Design” shall mean the requirements found in the 

following regulations: 

i.	 40 C.F.R. § 60.18(d); 

ii.	 40 C.F.R. § 63.11(b)(1); 

iii.	 40 C.F.R. §§ 60.482-10(d), 60.482-10a(d), but only to the extent 

that these provisions require compliance with 40 C.F.R. 

§ 60.18(d); 

iv.	 40 C.F.R. §§ 60.482-10(e), 60.482-10a(e), but only to the extent 

that these provisions relate to flares; 

v.	 40 C.F.R. §§ 60.592(a), 60.592a(a), but only to the extent that 

these provisions: (1) relate to flares; and (2) require compliance 

with 40 C.F.R. § 60.18(d); 

vi.	 40 C.F.R. § 63.643(a)(1), but only to the extent that this provision 

requires compliance with 40 C.F.R. § 63.11(b)(1); 

vii.	 40 C.F.R. § 63.648(a), but only to the extent that this 

provision: (1) relates to flares; and (2) requires compliance with 

40 C.F.R. § 60.18(d); and 

viii.	 40 C.F.R. § 63.1566(a)(1)(i) and Table 15 but only to the extent 

that this provision: (1) relates to flares; and (2) requires 

compliance with 40 C.F.R. § 63.11(b)(1). 

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g.	 “Subpart Ja Requirements” shall mean the following requirements of 

40 C.F.R. Part 60, Subpart Ja (in effect as of November 13, 2012): 

i.	 H2S emission limit applicable to flares (set forth in 40 C.F.R. 

§ 60.103a(h)); 

ii.	 H2S monitoring for flares (set forth in 40 C.F.R. § 60.107a(a)(2)); 

iii.	 Sulfur monitoring for flares (set forth in 40 C.F.R. § 60.107a(e)); 

and 

iv.	 Flow monitoring for flares (set forth in 40 C.F.R. § 60.107a(f)) . 

124. Entry of this Consent Decree shall resolve the civil claims of the United States for 

the violations alleged in the Complaint filed in this action through the Date of Lodging. 

125. Resolution of Claims for Violating PSD/NNSR Requirements at the Covered 

Flares. With respect to emissions of H2S, SO2, VOCs, and CO from the Covered Flares, entry of 

this Consent Decree shall resolve the civil claims of the United States against SDP for violations 

of the PSD/NNSR Requirements resulting from construction or modification from the date of the 

pre-Lodging construction or modification through: (i) for the SDP Refinery Covered Flares, 

December 31, 2017; (ii) for the Olefins Flares, December 31, 2017; and (iii) for the HIPA Flare, 

24 months after the Date of Entry. 

126. Resolution of Pre-Lodging Claims at the Covered Flares for Failing to Comply 

with: (a) BTU/scf Flared Gas Requirements; (b) General Flare Requirements; (c) Good Air 

Pollution Control Practice Requirements; and (d) Requirements Related to Monitoring, 

Operation, and Maintenance According to Flare Design. With respect to emissions of the 

following pollutants from the Covered Flares, entry of this Consent Decree shall resolve the civil 

claims of the United States against SDP for violations of the following requirements from the 

date those claims accrued through the Date of Lodging: 

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Pollutant(s) Requirement/Regulation 

VOCs and HAPs BTU/scf Flared Gas Requirements 

VOCs and HAPs General Flare Requirements 

VOCs and HAPs Good Air Pollution Control Practice Requirements 

VOCs and HAPs Requirements Related to Monitoring, Operation, 

and Maintenance According to Flare Design 

127. Resolution of Pre-Lodging Claims for Failing to Comply with 40 C.F.R. Part 60, 

Subpart J. 

a. SDP Refinery Covered Flares. With respect to emissions of SO2 and H2S 

from the SDP Refinery Covered Flares, entry of this Consent Decree shall resolve the civil 

claims of the United States against SDP for violations of 40 C.F.R. Part 60, Subpart J, from the 

date those claims accrued through the Date of Lodging. 

b. SDP Chemical Plant Covered Flares. With respect to emissions of SO2 

and H2S from the SDP Chemical Plant Covered Flares (as specifically identified in 

Subparagraphs 127.b.i–iii), entry of this Consent Decree shall resolve the civil claims of the 

United States against SDP for violations of 40 C.F.R. Part 60, Subpart J, from the date those 

claims accrued through the Date of Lodging, provided that the claims arose due to one the 

following: 

i.	 Fuel Gas flowing from the SDP Refinery to the Olefins II and III 

Flares during emergency situations; or 

ii.	 Gas flowing to the Olefins Flares as a result of refinery streams 

being processed at the Butane Butylene Hydrotreater Unit; or 

iii.	 Gas redirected from the Girbotol Flare at the SDP Refinery to the 

A&S and HIPA Flares. 

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128. Resolution of Claims Continuing Post-Lodging for Failing to Comply with: 

(a) Requirements Related to Monitoring, Operation, and Maintenance According to Flare 

Design; and (b) 40 C.F.R. Part 60, Subpart J at Olefins Flares. 

a. Requirements Related to Monitoring, Operation, and Maintenance 

According to Flare Design for all Covered Flares. With respect to emissions of VOCs and HAPs 

from the Covered Flares, entry of this Consent Decree shall resolve the civil claims of the United 

States against SDP for the violations set forth in Subparagraph 128.a.i, for the time frame set 

forth in Subparagraph 128.a.ii: 

i.	 Violations of Requirements Related to Monitoring, Operation, and 

Maintenance According to Flare Design, but only to the extent that 

the claims are based on SDP’s use of too much steam in relation to 

Vent Gas flow; 

ii.	 The resolution of liability in Subparagraph 128.a.i extends from 

the Date of Lodging through, for each Covered Flare, the date in 

Column C of Appendix 2.1 that is associated with that Covered 

Flare. 

b. 40 C.F.R. Part 60, Subpart J at the Olefins Flares. With respect to 

emissions of SO2 and H2S from the Olefins Flares, entry of this Consent Decree shall resolve 

the civil claims of the United States against SDP for violations of 40 C.F.R. Part 60, Subpart J, 

from the Date of Lodging through, for the Olefins Flares, the following dates, for claims that are 

based on the following circumstances: 

i.	 December 31, 2014, for claims based on Fuel Gas flowing from 

the SDP Refinery to the Olefins II and III Flares during emergency 

situations; and 

ii.	 December 31, 2016, for claims based on gas flowing to the Olefins 

Flares as a result of refinery streams being processed at the Butane 

Butylene Hydrotreater Unit. 

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129. Resolution of Claims under Subpart Ja Requirements. Entry of this Consent 

Decree shall resolve the civil claims of the United States against SDP for violations of the 

following Subpart Ja Requirements from November 13, 2012, through, for each SDP Refinery 

Covered Flare, the following: 

H2S Emission Limits 

(40 C.F.R. § 60.103a(h)) 

Sulfur and Flow Monitoring 

(40 C.F.R. §§ 60.107a(e),(f)) 

November 11, 2015 November 11, 2015 

130. Resolution of Title V Violations. Entry of this Consent Decree shall resolve the 

civil claims of the United States against SDP for the violations of Sections 502(a), 503(c), and 

504(a) of the CAA, 42 U.S.C. §§ 7661a(a), 7661b(c), 7661c(a), and of 40 C.F.R. §§ 70.1(b), 

70.5(a) and (b), 70.6(a) and (c), and 70.7(b), that are based upon the violations resolved by 

Paragraphs125–129 for the time frames set forth in those Paragraphs. 

131. Reservation of Rights: Resolution of Liability in Paragraphs 125 and 128–130 

can be Rendered Void. Notwithstanding the resolution of liability in Paragraphs 125 and 128– 

130 for the period of time between the Date of Lodging and the Post-Lodging Compliance Dates, 

those resolutions of liability shall be rendered void if SDP materially fails to comply with any of 

the obligations and requirements of Sections V and VI of this Decree (Compliance Requirements 

and Emission Credit Generation). However: 

a. To the extent that a material failure involves a particular Covered 

Facility(ies), the resolution of liability shall be rendered void only with respect to claims 

involving that particular Covered Facility(ies); 

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b. The resolutions of liability in Paragraphs 125 and 128–130 shall not be 

rendered void if SDP, as expeditiously as practicable, remedies such material failure and pays all 

stipulated penalties due as a result of such material failure. 

132. The United States reserves all legal and equitable remedies available to enforce 

the provisions of this Consent Decree, except as expressly stated in Paragraphs 125–130. This 

Consent Decree shall not be construed to limit the rights of the United States to obtain penalties 

or injunctive relief under the CAA or implementing regulations, or under other federal or state 

laws, regulations, or permit conditions, except as expressly specified in Paragraphs 125–130. 

The United States further reserves all legal and equitable remedies to address any imminent and 

substantial endangerment to the public health or welfare or the environment arising at, or posed 

by the Covered Facilities, whether related to the violations addressed in this Consent Decree or 

otherwise. 

133. In any subsequent administrative or judicial proceeding initiated by the United 

States for injunctive relief, civil penalties, other appropriate relief relating to the Covered 

Facilities or SDP’s CAA violations, SDP shall not assert, and may not maintain, any defense or 

claim based upon the principles of waiver, res judicata, collateral estoppel, issue preclusion, 

claim preclusion, claim-splitting, or other defenses based upon any contention that the claims 

raised by the United States in the subsequent proceeding were or should have been brought in the 

instant case, except with respect to claims that have been specifically resolved pursuant to 

Paragraphs 125–130 of this Section and for which the resolution of liability has not been voided 

pursuant to Paragraph 131. 

134. This Consent Decree is not a permit, or a modification of any permit, under any 

federal, state, or local laws or regulations. SDP is responsible for achieving and maintaining 

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complete compliance with all applicable federal, state, and local laws, regulations, and permits; 

and SDP’s compliance with this Consent Decree shall be no defense to any action commenced 

pursuant to any such laws, regulations, or permits, except as set forth herein. The United States 

does not, by its consent to the entry of this Consent Decree, warrant or aver in any manner that 

SDP’s compliance with any aspect of this Consent Decree will result in compliance with 

provisions of the Act, 42 U.S.C. § 7401 et seq., or with any other provisions of federal, state, or 

local laws, regulations, or permits. 

135. This Consent Decree does not limit or affect the rights of SDP or the United 

States against any third parties that are not party to this Consent Decree, nor does it limit the 

rights of third parties that are not party to this Consent Decree against SDP, except as otherwise 

provided by law. 

136. This Consent Decree shall not be construed to create rights in, or grant any cause 

of action to, any third party not party to this Consent Decree. 

XV. COSTS 

137. The Parties shall bear their own costs of this action, including attorneys fees, 

except that the United States shall be entitled to collect the costs (including attorneys fees) 

incurred in any action necessary to enforce this Consent Decree or to collect any portion of the 

civil penalty or any stipulated penalties due but not paid by SDP. 

XVI. NOTICES 

138. Unless otherwise specified herein, whenever notifications, submissions, or 

communications are required by this Consent Decree, they shall be made in writing and 

addressed to the persons set forth below. Submission by U.S. mail or courier is required and 

shall be sufficient to comply with the notice requirements of this Consent Decree; however, for 

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the submission of technical information or data, SDP shall submit the data in electronic form 

(e.g., a disk or hard drive). The email addresses listed below are to permit the submission of 

courtesy copies. 

Notice or submission to the United States: 

Chief, Environmental Enforcement Section 

Environment and Natural Resources Division 

U.S. Department of Justice 

Box 7611 Ben Franklin Station 

Washington, DC 20044-7611 

Re: DOJ No. 90-5-2-1-09388/1 

Notice or submission to EPA: 

Director, Air Enforcement Division 

Office of Civil Enforcement 

U.S. Environmental Protection Agency 

Mail Code 2242-A 

Regular Mail: 1200 Pennsylvania Ave, N.W. 

Ariel Rios Building South 

Room 1119 

Washington, DC 20460-0001 

Express Mail: Use same address but use 20004 as the zip code 

and
 

Associate Director
 

Air, Toxics, and Inspections Coordination Branch (6 EN-A)
 

U.S. EPA, Region 6 

1445 Ross Avenue 

Dallas, Texas 75202 

For courtesy purposes, electronic copies to: 

parrish.robert@epa.gov 

foley.patrick@epa.gov 

crawford.dorothy@epa.gov 

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Notice or submission to SDP: 

Kimberly Z. Lesniak 

Senior Legal Counsel 

Shell Oil Company 

One Shell Plaza 

910 Louisiana Street 

Houston, TX 77002 

For courtesy purposes: kim.lesniak@shell.com 

Shari Keller 

Sr. Staff Environmental Specialist-Air Compliance 

Shell Oil Products 

Environmental Affairs (OSP 2804B) 

910 Louisiana Houston, TX 77002 

For courtesy purposes: shari.keller@shell.com 

Richard Bourns 

Environmental Manager 

Shell Deer Park Site 

Shell Oil Products Company, LLC 

Shell Deer Park, 5900 Highway 225 East, 

Deer Park, TX 77536 

For courtesy purposes: richard.bourns@shell.com 

Any Party may, by written notice to the other Party, change its designated notice recipient(s) or 

notice address(es) provided above. Notices submitted pursuant to this Section shall be deemed 

submitted upon mailing, unless otherwise provided in this Consent Decree or by mutual 

agreement of the Parties in writing. 

XVII. EFFECTIVE DATE 

139. The Effective Date of this Consent Decree shall be the date upon which this 

Consent Decree is entered by the Court or a motion to enter the Consent Decree is granted, 

whichever occurs first, as recorded on the Court’s docket; provided however, that SDP hereby 

agrees that it shall be bound to perform duties scheduled to occur prior to the Effective Date. In 

the event the United States withdraws or withholds consent to this Consent Decree before entry, 

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or the Court declines to enter this Consent Decree, then the preceding requirement to perform 

duties scheduled to occur before the Effective Date shall terminate. 

XVIII. RETENTION OF JURISDICTION 

140. The Court shall retain jurisdiction over this case until termination of this Consent 

Decree for the purposes of resolving disputes arising under this Decree, entering orders 

modifying this Decree, or effectuating or enforcing compliance with the terms of this Decree. 

XIX. MODIFICATION 

141. Except as provided in Paragraph 9, the terms of this Consent Decree may be 

modified only by a subsequent written agreement signed by the United States and SDP. Where 

the modification constitutes a material change to any term of this Consent Decree, it shall be 

effective only upon approval by the Court. 

142. Except as provided in Paragraphs 5–9, any disputes concerning modification of 

this Decree shall be resolved pursuant to Section XII of this Decree (Dispute Resolution); 

provided, however, that instead of the burden of proof as provided by Paragraph 115, the Party 

seeking the modification bears the burden of demonstrating that it is entitled to the requested 

modification in accordance with Federal Rule of Civil Procedure 60(b). 

XX. TERMINATION 

143. Termination for the SDP Chemical Plant, the SDP Refinery or Entire Consent 

Decree. If the conditions precedent to termination set forth in Paragraph 144 are satisfied, the 

requirements of this Consent Decree that are applicable to either the SDP Chemical Plant or the 

SDP Refinery may be subject to termination or all of the requirements in this Consent Decree 

may be subject to termination. 

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144. Termination: Conditions Precedent. Prior to termination, SDP must have 

completed all of the following requirements of this Consent Decree: 

a. Payment of all civil penalties, stipulated penalties and other 

monetary obligations; 

b. Satisfactory compliance with all provisions of Section V of this Decree 

(Compliance Requirements) with respect to all of the Covered Flaresat the 

Facility(ies) that is(are) subject to the termination request; 

c. Operation for at least one year in satisfactory compliance with the 

limitations and standards set forth in Paragraphs 41, 40.b, 47.b, 49, 56.b, 

56.c, 57.b, 58.c (if and as applicable), 58.d (if and as applicable), and 59 

for all of the Covered Flares at the Facility(ies) that is(are) subject to the 

termination request; 

d. Completion of the Mitigation Projects in Section VII; 

e. Completion of the Supplemental Environmental Project in Section VIII; 

f. Application for and receipt of all non-Title V air permits necessary to 

ensure survival of the Consent Decree limits and standards after 

termination of this Consent Decree (the Paragraph 67 requirement) for all 

of the flares at the Facility(ies) that is(are) subject to the termination 

request; 

g. Application for a modification or amendment to the Title V permit to 

incorporate the limits and standards in Paragraph 67 into the Title V 

permit of the Facility(ies) that is(are) subject to the termination request; 

and 

h. Application for such modifications, amendments, or revisions to the 

Covered Facilities’ NPDES permit as may be necessary as a result of the 

Mitigation Project required in Paragraph 71 of this Consent Decree 

(“Mitigation Project: North Effluent Treater Controls”). 

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145. Termination: Procedure. 

a. At such time as SDP believes that it has satisfied the conditions for 

termination set forth in Paragraph 144 for either the SDP Chemical Plant or the SDP Refinery or 

for the entire Consent Decree, SDP may submit a request for termination to the United States by 

certifying such compliance in accordance with the certification language in Paragraph 89. In the 

Request for Termination, SDP must demonstrate that it has satisfied the conditions for 

termination set forth in Paragraph 144. The Request for Termination shall include all necessary 

supporting documentation. 

b. Following receipt by the United States of SDP’s Request for Termination, 

the Parties shall confer informally concerning the Request. If the United States agrees that the 

Decree may be terminated, the Parties shall submit, for the Court's approval, a joint stipulation 

terminating the Decree. 

c. If the United States does not agree that the Consent Decree may be 

terminated, or if SDP does not receive a written response from the United States within 60 days 

of SDP’s submission of the Request for Termination, SDP may invoke dispute resolution under 

Section XII of this Decree (Dispute Resolution). 

XXI. PUBLIC PARTICIPATION 

146. This Consent Decree shall be lodged with the Court for a period of not less than 

30 days for public notice and comment in accordance with 28 C.F.R. § 50.7. The United States 

reserves the right to withdraw or withhold its consent if the comments regarding the Consent 

Decree disclose facts or considerations indicating that the Consent Decree is inappropriate, 

improper, or inadequate. SDP consents to entry of this Consent Decree without further notice 

and agrees not to withdraw from or oppose entry of this Consent Decree by the Court or to 

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challenge any provision of the Decree unless the United States has notified SDP in writing that it 

no longer supports entry of the Decree. 

XXII. SIGNATORIES/SERVICE 

147. Each undersigned representative of SDP and the Assistant Attorney General for 

the Environment and Natural Resources Division of the Department of Justice (or his or her 

designee), certify that he or she is fully authorized to enter into the terms and conditions of this 

Consent Decree and to execute and legally bind the Party he or she represents to this document. 

148. This Consent Decree may be signed in counterparts, and its validity shall not be 

challenged on that basis. SDP agrees to accept service of process by mail with respect to all 

matters arising under or relating to this Consent Decree and to waive the formal service 

requirements set forth in Rules 4 and 5 of the Federal Rules of Civil Procedure and any 

applicable Local Rules of this Court including, but not limited to, service of a summons. 

XXIII. INTEGRATION 

149. This Consent Decree and its Appendices constitute the final, complete, and 

exclusive agreement and understanding among the Parties with respect to the settlement 

embodied in this Consent Decree and its Appendixes and supersede all prior agreements and 

understandings, whether oral or written, concerning the settlement embodied herein. No other 

document, except for any plans or other deliverables that are submitted pursuant to this Decree, 

nor any representation, inducement, agreement, understanding, or promise, constitutes any part 

of this Decree or the settlement it represents, and no such extrinsic document or statement of any 

kind shall be used in construing the terms of this Decree. 

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XXIV. FINAL JUDGMENT
 

150. Upon approval and entry of this Consent Decree by the Court, this Consent 

Decree shall constitute a final judgment of the Court in this action as to the United States and 

SDP. The Court finds that there is no just reason for delay and therefore enters this judgment as 

a final judgment under Fed. R. Civ. P. 54 and 58. 

DATED this day of 2013. 

UNITED STATES DISTRICT JUDGE 

SOUTHERN DISTRICT OF TEXAS 

109
 
 

 

 

 

 

 

Case 4:13-cv-02009 Document 2-1 Filed in TXSD on 07/10/13 Page 115 of 121 

We hereby consent to the entry of the Consent Decree in the matter of United States, v. Shell Oil 

Company, et al., subject to public notice and comment. 

FOR THE UNITED STATES OF AMERICA
 

s/ Robert G. Dreher 

ROBERT G. DREHER 

Acting Assistant Attorney General 

Environment and Natural Resources Division 

United States Department of Justice 

s/ Robert D. Parrish 

ROBERT D. PARRISH 

DOJ Attorney by Special Appointment 

Environmental Enforcement Section 

Environment and Natural Resources Division 

Department of Justice 

1200 Pennsylvania Ave., NW 

Washington, DC 20460 

(202) 564-6946 (phone) 

parrish.robert@epa.gov 

s/ Annette M. Lang 

ANNETTE M. LANG 

Senior Counsel 

Environmental Enforcement Section 

Environment and Natural Resources Division 

Department of Justice 

P.O. Box 7611 

Washington, D.C. 20044-7611 

(202) 514-4213 (phone) 

(202) 616-6584 (fax) 

annette.lang@usdoj.gov 
 

 

 

Case 4:13-cv-02009 Document 2-1 Filed in TXSD on 07/10/13 Page 116 of 121 

KENNETH MAGIDSON 

United States Attorney 

Southern District of Texas 

By:	 s/ Keith Edward Wyatt 

KEITH EDWARD WYATT 

Assistant United States Attorney 

Texas Bar No. 22092900 

Federal Bar No. 3480 

1000 Louisiana St., Suite 2300 

Houston, TX 77002 

Telephone: (713) 567-9713 

Fax: (713) 718-3303 
 

 

 

Case 4:13-cv-02009 Document 2-1 Filed in TXSD on 07/10/13 Page 117 of 121 

We hereby consent to the entry of the Consent Decree in the matter of United States v. Shell Oil 

Company, et al., subject to public notice and comment. 

FOR THE UNITED STATES ENVIRONMENTAL 

PROTECTION AGENCY 

s/ Cynthia Giles*** 

CYNTHIA GILES 

Assistant Administrator 

Office of Enforcement and Compliance Assurance 

United States Environmental Protection Agency 

Washington, DC 

s/ Susan Shinkman*** 

Susan Shinkman 

Director, Office of Civil Enforcement 

Office of Enforcement and Compliance Assurance 

United States Environmental Protection Agency 

Washington, DC 

s/ Phillip A. Brooks*** 

PHILLIP A. BROOKS 

Director, Air Enforcement Division 

Office of Enforcement and Compliance Assurance 

United States Environmental Protection Agency 

Washington, DC 

*** Signed with permission. 
 

 

 

Case 4:13-cv-02009 Document 2-1 Filed in TXSD on 07/10/13 Page 118 of 121 

We hereby consent to the entry of the Consent Decree in the matter of United States v. Shell Oil 

Company, et al., subject to public notice and comment. 

FOR THE UNITED STATES ENVIRONMENTAL 

PROTECTION AGENCY 

REGION 6 

s/ John Blevins*** 

JOHN BLEVINS 

Director 

Compliance Assurance and Enforcement Division 

EPA Region 6 

Dallas, TX 

*** Signed with permission. 
 

 

 

 

 

Case 4:13-cv-02009 Document 2-1 Filed in TXSD on 07/10/13 Page 119 of 121 

We hereby consent to the entry of the Consent Decree in the matter United States v. Shell Oil 

Company, et al. 

FOR SHELL OIL COMPANY 

By: s/ Barry J. Klein*** 

BARRY J. KLEIN 

General Manager 

Deer Park Site 

5900 Highway 225 East 

Deer Park, TX 77536 

Shell Oil Products Company LLC, as Agent for Shell Oil 

Company 

*** Signed with permission. 
 

 

 

 

 

 

 

Case 4:13-cv-02009 Document 2-1 Filed in TXSD on 07/10/13 Page 120 of 121 

We hereby consent to the entry of the Consent Decree in the matter of United States v. Shell Oil 

Company, et al. 

FOR DEER PARK REFINING LIMITED PARTNERSHIP
 

By: s/ Barry J. Klein*** 

BARRY J. KLEIN 

General Manager 

Deer Park Site 

5900 Highway 225 East 

Deer Park, TX 77536 

Shell Oil Products Company LLC, as Agent for Shell Oil 

Company, General Partner 

*** Signed with permission. 
 

 

 

 

 

 

Case 4:13-cv-02009 Document 2-1 Filed in TXSD on 07/10/13 Page 121 of 121 

We hereby consent to the entry of the Consent Decree in the matter of United States v. Shell Oil 

Company, et al. 

FOR SHELL CHEMICAL LP 

By: s/ Barry J. Klein*** 

BARRY J. KLEIN 

General Manager 

Deer Park Site 

5900 Highway 225 East 

Deer Park, TX 77536 

Shell Oil Products Company LLC, as Agent for Shell 

Chemical LP 

*** Signed with permission. 
Case 4:13-cv-02009 Document 2-2 Filed in TXSD on 07/10/13 Page 1 of 75 

UNITED STATES
 

v. 

SHELL OIL COMPANY, ET AL. 

APPENDICES TO CONSENT DECREE 

APPENDIX 1.1 

DRAWINGS ILLUSTRATING 

LOWER, CENTER, AND UPPER STEAM 

INJECTION IN VARIOUS TYPES OF FLARE TIPS 
 

 

 

 

 

Case 4:13-cv-02009 Document 2-2 Filed in TXSD on 07/10/13 Page 2 of 75 Appendix 1.1 

Type II 

Exit Lower 

Steam/Air 

Mixture 

Pilot 

Steam/Air 

Tubes 

Stability Ring 

Type I 

Upper 

Steam 

Center 

Steam 

Pilot Stability Tab 

Upper 

Steam 

B 

A 

Center 

Steam 

Pilot 

Stability Tab 

Upper 

Steam 

Lower 

Steam 

Key: 

Yellow = Vent Gas 

Red = Fire 

Light Blue = Steam / Air 

Dark Blue = Steam 
 

 

 

 

 

Case 4:13-cv-02009 Document 2-2 Filed in TXSD on 07/10/13 Page 3 of 75

Type IV 

Pilot 

Type III 

Pilot 

Stability Tabs 

Modules 

Upper 

Steam 

Lower 

Steam 

Key: 

Yellow = Vent Gas 

Red = Fire 

Light Blue = Steam / Air 

Dark Blue = Steam 
Case 4:13-cv-02009 Document 2-2 Filed in TXSD on 07/10/13 Page 4 of 75 

UNITED STATES
 

v. 

SHELL OIL COMPANY, ET AL. 

APPENDICES TO CONSENT DECREE 

APPENDIX 1.2 

GENERAL EQUATIONS 
 

 

 

 

 

 

 

 

Case 4:13-cv-02009 Document 2-2 Filed in TXSD on 07/10/13 Page 5 of 75 

APPENDIX 1.2 

GENERAL EQUATIONS 

Equation 1: “Combustion Efficiency” or “CE”: 

CE = [CO2]/([CO2] + [CO] + [OC])

 where: 

[CO2] = Concentration in volume percent or ppm-meters of carbon dioxide 

in the combusted gas immediately above the Combustion Zone 

[CO] = Concentration in volume percent or ppm-meters of carbon 

monoxide in the combusted gas immediately above the 

Combustion Zone 

[OC] = Concentration in volume percent or ppm-meters of the sum of all 

organic carbon compounds in the combusted gas immediately 

above the Combustion Zone, counting each carbon molecule 

separately where the concentration of each individual compound is 

multiplied by the number of carbon atoms it contains before 

summing (e.g., 0.1 volume percent ethane shall count as 0.2 

percent OC because ethane has two carbon atoms) 

For purposes of using the CE equation, the unit of measurement for CO2, CO, and 

OC must be the same; that is, if “volume percent” is used for one compound, it 

must be used for all compounds. “Volume percent” cannot be used for one or 

more compounds and “ppm-meters” for the remainder. 

Equation 2: “Center Steam Mass Flow Rate” or “ṁs-cen ”: 

ṁs-cen = Qs-cen x (18/385.5)

 where: 

Qs-cen = Center Steam Volumetric Flow Rate 

Equation 3: “Total Steam Mass Flow Rate” or “ṁs”: 

ṁs = Qs x (18/385.5)

 where: 

Qs = Total Steam Volumetric Flow Rate 

1 of 2 
Case 4:13-cv-02009 Document 2-2 Filed in TXSD on 07/10/13 Page 6 of 75 

APPENDIX 1.2
	

Equation 4: “Vent Gas Mass Flow Rate” or “ṁvg”: 

ṁvg = Qvg x (MWvg/385.5) 

where: 

Qvg = Vent Gas Volumetric Flow Rate 

MWvg = Molecular Weight, in pounds per pound-mole, of the Vent Gas, as 

measured by the Vent Gas Average Molecular Weight Analyzer 

described in Paragraph 19 of this Consent Decree 

[End of Appendix 1.2] 

2 of 2 
Case 4:13-cv-02009 Document 2-2 Filed in TXSD on 07/10/13 Page 7 of 75 

UNITED STATES
 

v. 

SHELL OIL COMPANY, ET AL. 

APPENDICES TO CONSENT DECREE 

APPENDIX 1.3 

CALCULATING NHVCZ-LIMIT AND NHVCZ FOR 

STREAM-ASSISTED FLARES 
Case 4:13-cv-02009 Document 2-2 Filed in TXSD on 07/10/13 Page 8 of 75 

APPENDIX 1.3 

CALCULATING NHVcz-limit AND NHVcz FOR STEAM-ASSISTED FLARES 

All abbreviations, constants, and variables are defined in the Key on Page 6 of this 

Appendix. 

Steps in the Calculations 

Step 1: Determine the Lower Flammability Limit (“LFL”) of Each Individual Vent Gas 

Compound 

Take the LFL values of each individual Vent Gas compound from Table 1 in this Appendix. 

Step 2: Calculate the LFL of the vent gas mixture 

The average lower flammability limit of the vent gas is calculated by Le Chatelier’s equation 

shown below as Equation 1. This calculation uses the weighted average of the LFLs of the 

individual compounds weighted by their volume fraction of the vent gas. All inerts, including 

nitrogen, are assumed to have an infinite lower flammability limit (e.g. LFLN2 = ∞). 

1

ݔ ൬

ܮܨܮ

ൌ ݃ݒܮܨܮ

݅ൌ1 ∑݊ ݅ Equation 1 ൰

݅

Step 3: Determine the Net Heating Value of the Vent Gas (NHVvg) 

If a Gas Chromatograph is used: The net heating value of the vent gas is calculated and 

reported from the GC at the conclusion of each analytical cycle (~10-15 minutes). Equation 2 is 

used by the GC to calculate the vent gas net heating value from each individual compound net 

heating value. Individual compound volume fractions, except for water, are measured directly 

by the GC. A company is not required to measure water in Vent Gas. If a company chooses to 

measure water, then: (i) if the water measurement is taken upstream of a knock-out drum, then 

water does not have to be included in the calculation of NHVvg; (ii) if no knock-out drum exists 

or if the water measurement is taken after the knock-out drum, then the company must include 

water in the calculation of NHVvg and adjust the concentration of the compounds measured by 

the GC to a wet basis. Individual compound net heating values, including water, are listed in 

Table 1 of this Appendix. 

݊

ܰ ·ܪܸ ݅ݔሺ ෍ൌ ݃ݒܸܪܰ

݅ൌ1

݅ሻ Equation 2

If a Net Heating Value Analyzer/Calculator is used: Use the measured value. 

NOTE: Table 1 includes two alternative values for the Net Heating Value of hydrogen: the 

actual NHV of hydrogen (274 BTU/scf) and an “adjusted” NHV of hydrogen (1212 BTU/scf). 

1 of 10 
Case 4:13-cv-02009 Document 2-2 Filed in TXSD on 07/10/13 Page 9 of 75 

APPENDIX 1.3 

Companies have the option of using either in calculating NHVvg; however, whichever option is 

selected also must be used in calculating NHVcz. 

Step 4: Calculate the NHVvg at its LFL (NHVvg-LFL) 

Using LFLvg from Equation 1 and NHVvg from Equation 2, the NHVvg-LFL is calculated by 

Equation 3. 

 3 Equation ݃ݒ ܮ ·ܨܮ ݃ݒ ܪܸ ܰ ൌ ܮ–݃ݒܮܨ ܸܪܰ

Step 5: Multiply NHVvg-LFL by the Combustion Efficiency Multipliers to calculate the 

NHVcz-limit 

The Net Heating Value of the Gases in the Combustion Zone (NHVcz) of a Flare that is needed to 

ensure an acceptable Combustion Efficiency is determined by multiplying NHVvg-LFL by 

Combustion Efficiency Multipliers appropriate to the flare category and the volume percent of 

hydrogen in the Vent Gas as defined in Table 2. 

The Net Heating Value of Combustion Zone Gas Limit is calculated as follows: 

 4 Equation ܮܨܮെ݃ݒ ܰ ·ܪܸ ൯݈݁݊݁ݕ݌݋ݎ݌ݔ·ܤ൅ ܣ൫ ൌ ݐ݈݅݉݅െݖܸܿܪܰ

Step 6: Calculate the Net Heating Value of the Combustion Zone Gas (NHVcz) 

The NHV in the combustion zone (NHVcz) combines the NHVs of the Vent Gas, pilot gas, and 

steam and is calculated by Equation 5a (based on mass flow measurement) or 5b (based on 

volumetric flow measurement). These two equations are equivalent for combustion zone 

conditions, as shown in Addendum A to this Appendix. The NHV of steam is assumed to be 

) are measured by on-line m ܳ ݎ݋ ௦ ) and steam flow rate ( zero. Vent Gas flow rate (mሶ vg ܳ ݎ݋ ௩௚ ሶ s

ܳ ݎ݋ (௚௣ is constant for each flare and set by an orifice. pg flow meters. The pilot gas flow rate (mሶ

௔௜௥

݉ሶ ௩௚ ܸܪ ·ܰ ௩௚ ൬ ܯܹ௩௚

݉ሶ ൰൅൬ܯܹ௚௣

݉ሶ ௣௚ ܸܪ ·ܰ ௚௣ ൰൅൬ ܯܹ௚௣

݉ሶ ൰ ൅ ቀ

௥௜௔ܹܯ

൰

ܰܪܸ௖௭ ൌ ሶ ݉ሶ ൰൅൬ ݉௩௚ ௣௚ ൬ ுమை

௦

ܹܯ ௚௩ܹܯ

൫ܳ௩௚ ܸכܪ ܰ ௩௚൯ ൅ ሺܳ௣௚ ܸכܪ ܰ௚௣ ሻ ܰܪܸ௖௭ ൌ ܳ௩௚ ൅ ܳ௣௚ ൅ ܳ௦ ൅ ܳ௔௜௥

ቁ

Equation 5a 

OR
 

Equation 5b 

2 of 10 
 

 

 

Case 4:13-cv-02009 Document 2-2 Filed in TXSD on 07/10/13 Page 10 of 75 

APPENDIX 1.3 

The values for ݉௦ሶ , , Qs and Qair are determined as follows based on the type of flare: ݉௔௜௥ ሶ

Steam-Assisted Flare without a Minimum Steam Reduction System (“MSRS”) 

݁ݑ݈ܽݒ ݁݀ݎݑݏ݉݁ܽ ൌ ௦ܳ ݎ݋  
ሶ݉

݉ሶ
 ௔௜௥ ݎ݋ ܳ ௥௜௔ൌ 0 ௦

Steam-Assisted Flare with MSRS 

ൌ ݉ ݈ ௦ ݉ሶ ௦ ݎ݋ ܳ

 ܳݎ݋ ሶ݉

݁ݑ

݊݋݅ݐܽݑݍܧ

ܽݒ ݁݀ݎݑݏ݁ܽ

 13 ݅݊݌݁ݐ6ܽ ܵ ݎݐ݈ݑݏ݉݁݋ݎ݂ ൌ௔௜௥ ௔௜௥ 

 OR 

݉ሶ  ݎ݋ ܳ ௥௜௔ൌ 0 with vendor certification that the MSRS equipment installed 

on the flare is not capable ሺeven at minimum vent gas flowሻ of 

inspirating more than twice the stoichiometric volume of air into 

the vent gas. 

The molecular weight of the vent gas (MWvg) is calculated by the GC using Equation 6. An 

on-line ultrasonic flow meter may also be used to calculate MWvg. Individual compound 

molecular weights are listed in Table 1 of this Appendix. 

௔௜௥

݃ݒܹܯ

݊

ݔ݅ ൌ ෍ሺ

݅ൌ1

· ܯܹ݅ሻ Equation 6 

The NHV of the pilot gas (NHVpg) and MW of the pilot gas (MWpg) are calculated using 

Equations 7 and 8, respectively. These calculations are similar to the vent gas calculations, 

except the individual compound volume fractions are that of the pilot gas and not the vent gas. 

Individual compound volume fractions are measured by laboratory analysis of a pilot gas sample, 

or may be taken from the natural gas supplier’s laboratory certificate of analysis. 

݊

෍൫

݅ൌ1

 7 Equation ൯ ݃݌ ݃݌ ݅ ܸܪܰ · ݅ ൌ ܸܪܰ

݊

෍൫

݅ൌ1

 8 Equation ൯ܹ݅ܯ · ݃݅݌ ൌ ݃݌ܹܯ

3 of 10 
 

 

ሶ

ሶ ሶ

ሶ

Case 4:13-cv-02009 Document 2-2 Filed in TXSD on 07/10/13 Page 11 of 75 

APPENDIX 1.3 

Step 6a: Calculation of air mass flow rate for flares equipped with MSRS.
 

The complete combustion of an organic compound comprised of a combination of carbon and 

hydrogen atoms is shown in Equation 9: 

ݕ ܱଶܪ ቁ

2 ቁ ܱଶ ՜ ݔ ܱܥ ଶ ൅ ቀ 4

 9 Equation ൅ ݔቀ ൅ ௬ܪ௫ܥ ݕ

Note: x and y values for each compound are found in Table 1 of this Appendix. 

Therefore, the stoichiometric oxygen molar flow rate (moles/hr) for any given combustible 

compound flow is defined by Equation 10a (mass basis) or Equation 10b (volumetric basis): 

ሶ ೡ೒

ெௐೡ೒൰ ቀݔ ൅ ௬

ቁ Equation 10a ସ

௠ ݊ைଶି௦௧௢௜௖௛ ൌ ݔ ௝൬

OR
 

ܳ௩௚ ݊ሶ

ைଶି௦௧௢௜௖௛ ൌ ݔ ௝൬

The stoichiometric oxygen mass flow rate for the vent gas (lb/hr) or stoichiometric oxygen 

volumetric flow rate for the vent gas (scfh) is given by Equation 11a (mass basis) or 11b 

(volumetric basis). 

ݕ ൅ ݔቀ ൰385.5

4

ቁ Equation 10b 

௡

ைଶି௦௧௢௜௖௛ೕ כ෍ ݊ ݉ைଶି௦௧௢௜௖௛ି௩௚ ൌ ܯܹைమ

௝ୀଵ

OR 

௡

ைଶି௦௧௢௜௖௛ೕ ܳைଶି௦௧௢௜௖௛ି௩௚ ൌ 385.5 כ෍ ݊

௝ୀଵ

Equation 11a 

Equation 11b 

The stoichiometric air mass flow rate (lb/hr) or stoichiometric air volumetric flow rate (scfh) for 

the vent gas is given by Equation 12a (mass basis) or Equation 12b (volumetric basis). 

݉௔௜௥ି௦௧௢௜௖௛ି௩௚ ൌ כ ݉ሶ ܱ2െ݋ݐݏ݄݅ܿെݒ݃ ሶ ܯܹܽ݅ݎ

ܹܯ ܱ2 0.21 · Equation 12a 

OR 

ܳ ݃ݒെ݄݅ܿ݋ݐݏെܱ2

ܳ௔௜௥ି௦௧௢௜௖௛ି௩௚ ൌ 0.21 Equation 12b 

4 of 10 
   

 

Case 4:13-cv-02009 Document 2-2 Filed in TXSD on 07/10/13 Page 12 of 75 

APPENDIX 1.3 

The air mass flow (lb/hour) or air volumetric flow (scfh) used in Equation 5a or 5b is given by 

subtracting two times the stoichiometric air from the total air provided by the MSRS. This is 

shown in Equation 13a and 13.b. 

݉ሶ ௔௜௥ ൌ ݉ሶ െ ሺ2 כ ݉ሶ ௔௜௥ିெௌோௌ

OR 

ܽ݅ݎെ݋ݐݏ݄݅ܿെݒ݃ሻ Equation 13a 

ሻ ܳܽ݅ݎെ݋ݐݏ݄݅ܿെݒ݃ ܳ ௥௜௔ൌ ܳ௔௜௥ିெௌோௌ െ ሺ2 כ Equation 13b 

The equation for ݉ሶ

by the MSRS vendor. The factor of 2 used in Equation 13 is based on the best information 

available as of the Date of Lodging. If new information becomes available thereafter, the parties 

may modify that factor; any such modification does not constitute a material modification to the 

Consent Decree. 

If ݉ሶ ௔௜௥ ൏ 0 then ݉ሶ

OR 

If ܳ௔௜௥ ൏ 0 ݐ ݄݊݁ ܳ ௥௜௔ൌ 0

௔௜௥ିெௌோௌ or ܳ௔௜௥ିெௌோௌ is specific to the MSRS installed and must be provided 

௔௜௥ ൌ 0

Step 7: Ensure that during flare operation, NHVcz ≥ NHVcz-limit 

The flare must be operated to ensure that NHVcz is equal to or above NHVcz-limit to ensure 

acceptable combustion efficiency. Equation 14 shows this relationship. 

 14 Equation ݐ݈݅݉݅െݖܿ ܪܸ ܰ ൒ ݖܸܿܪܰ

5 of 10 
   

   

         

  

   

       

      

   

     

  

        

  

   

   

       

 

Case 4:13-cv-02009 Document 2-2 Filed in TXSD on 07/10/13 Page 13 of 75 

APPENDIX 1.3 

Key to the Abbreviations: 

ሻ

ሺ ݂݋݃݁݊ ݕݔ݋ ݅݊ ݎܽ݅ ݊݋݅ݐܽܿݎ ݂ ݈݁݉݋ ൌ 0.21 ଶܱ ݈݉݋ –0.21 ݈ܾ ሻ ݉– ݋݈݅ܽݎ ⁄݈ܾ

݈݈݋݉‐ܾ ݂ܿ⁄ݏ 385.5ሺ ܾ݅ܿݑ ܿݐ ݂݁݁ ݀ݎܽ݊݀ܽݐݏ  ݏ݈݁݋ ݉݋ݐ  ݊݀ݑ݋݌݉ ݋ݎ݊ ݂݋݅ݏݎ݁ݒ݊݋ܿ ൌ 385.5

ሻݏݏ݈݁ݐ݊݅ݑሺ௅ ி௅ି௚௩ܸܪܰ ݂ݎ݋ ݈݌݁݅݅ݎ ݐ݈ݑ݉ ݂݂݅ܿ݅݁݁ݕ݊ܿ ݊݋݅ݐݏݑܾ݉݋ܿ ݁ݒ݋ݎ݈݈ܽ ൌ ܣ

ሻݏݏ݈݁ݐ݊݅ݑሺ ௅ி௅ି௚௩ ݎ݋ܸ ݂ܪܰ ݎ݈݅݁݌݅ݐ݈ݑ ݉ݕ݂݂݁݅ܿ݅݁݊ܿ ݊݋݅ݐݏݑܾ݉݋݈݁݊݁ ܿݕ݌݋ݎ݌ ൌ ܤ

௚௩ܥ ሻ% ݈݋ݒሺ ݂݋ ܥ݄݁ ݅݊ ܸܱݐ ݐ݁݊ݒ ݏ ݃ܽ ݊݋݅ݐܽݎݐ݊ܿ݁݊݋ܿ ൌ

ሻݏݏ݈݁ݐ݊݅ݑሺ1   ܾ݈ܶܽ݁ ݅݊ ݉݊ݑ݈݋݅ ܿ ݉݋ݎ݂ ݊݀ݑ݋݌݉݋݁݀ ܿݎܾ݉݁ݑ݈ܽ ݊ݑ݅݀ݒ݅݊݀݅ ൌ ݅

ሻݏݏ݈݁ݐ݊݅ݑሺ1  ݉݊ݑ݈݋ ܾ݈ܶܽ݁ ݅݊ ݆ ܿ ݉݋ݎ݊݀ ݂ݑ݋݌݉݋ܿ ݁݀ݎܾ݉݁ݑ݈ܽ ݊ݑ݅݀ݒ݅݊݀݅ ൌ ݆

ሻݏݏ݈݁ݐ݊݅ݑሺ݊݁ ݋ݖ݊ ݋݅ݐݏݑܾ݉݋݄݁ ܿݐ  ݋݂ ݐ݊݁݊݋݌݉݋ ܿݏݑ݋݁ݏ݈ܽ ݃ܽݑ݅݀ݒ݅݊݀݅ ൌ ݇

ሻ% ݈݋ݒሺ ݊݀ݑ݋݌݉݋݈ܽ ܿݑ݅݀ݒ݅݊݀݅ ݐ݂ ݈݅݉݅݋  ݕݐ ݂݈ܾ݈ܽ݉݉ܽ݅݅ݎ݁ݓ݋ ௜ ݈ ൌ ܮܨܮ

௚௩ܮܨܮ ሻ% ݈݋ݒሺ ݏ ݃ܽ ݐ݂ ݈݅݉݅݋ ݐ݁݊ݒ ݕݐ ݂݈ܾ݈ܽ݉݉ܽ݅݅ ݈ݎ݁ݓ݋ ൌ

ሻݎ݈ܾ/݄ሺ ݓ݋݁ ݂݈ݐܽݎ݂ ݋ ݎ ܽ݅ ݉ݏݏܽ ൌ ௔௜௥ ሶ݉

ݎܽ݅ ݁ݐܽݎ݂ ݋ ݏݏ ݉ܽݓ݋݂݈ ݈ܽݐ݋ݐ ൌ ெௌோௌି ௔௜௥ሶ݉

݉ሶ

݉ሶ

݉ሶ

݉ሶ

݉ሶ

݉ሶ

݊ሶ

ሻݎ݈ܾ/݄ሺ ݕܴܵܵ ܽ݊ ܾܯ  ܿ݁݀ݑ݀݋ݎݐ݅݊

 
௚௩ି ௖௛ሻݎ݈ܾ/݄ሺ ݎ ܽ݅ݏݏ ݉ܽݓ݋ ݂݈ݎ݋݄݁ ݂ݐ ݐ݁݊ݒ ݏ݃ܽ ݅ܿݎݐ݉݁݋݄݅ܿ݅݋ݐݏ ൌ

ሻݎ݈ܾ/݄ሺ ݐ݊݁݊݋݌݉݋ܿ ݊݁݋ݖ ݏ݃ܽ ݊݋݅ݐݏݑܾ݉݋ܿ ݂ ݉ݏݏܽ ൌ௞ 

ሻ ݄ݎ ݈ܾ⁄ሺ ݎ݋݄݁ ݂ݐ ݐ݁݊ݒ ݏ ݃ܽ ݓ݋݂݈ ݏݏ݃݁݊ ݉ܽݕݔ݋݅ܿ ݎݐ݉݁݋݄݅ܿ݅݋ݐݏ ൌ௚
 ௩ି௢௜௖௛௦௧ିைଶ

௔௜௥ି௦௧௢௜

ݒܽ݅݊݀݅ݑ݈݅݀ ݂݋ ݎ݁ݐܽ ݈ݓ݋

(ݎ݈ܾ/݄ሺ ݓ݋݁ ݂݈ݐܽݎ݂ ݋ ݐ݋݈݅݌ ݏ ݃ܽ ݉ݏݏܽ ൌ௣௚ 

ሻ ܾݎ/݄ ݈ሺ ݈ܽݐ݋ݐ݁ ݐݏܽ݉ ݂݋ ݎ݁ݐܽ ݓ݋ ݈݂ ݉ݏݏܽ ൌ ௦

ሻݎ݈ܾ/݄ሺ ݏ݃ܽ ݐ ݁ݒ݊ ݂݋ ݎ݁ݐܽ ݈݂ݓ݋ ݉ݏݏܽ ൌ௚ ௩

ሻݎ݈⁄݄݋݉ሺ ݊݀ݑ݋݌݉݋ܿ ݈ܽݑ݅݀ݒܽ݊ ݅݊݀݅ ݎ݋݂ ݓ ݎ݈ܽ݋ ݉݋݂݈ ݃݁݊ݕݔ݋݅ܿ ݎݐ݉݁݋݄݅ܿ݅݋ݐݏ ൌ௢௜௖௛ ௦௧ିைଶ

ுమܹܯ ሻ݈݋݉ –18.02 ݈ܾ/݈ܾሺ ݐ݄݁݅݃ݓ݂ ݋ ݎ݁ݐܽݓ  ݉ݎ݈ܽݑ݈݁ܿ݋ ൌ ை

ሻ݈݋݉ –݈ܾ/݈ܾሺ ݊݀ݑ݋݌݉݋݈ܽ ܿݑ݅݀ݒ ݅݊݀݅ ݐ݄݁݅݃ݓ݂ ݋  ݉ݎ݈ܽݑ݈݁ܿ݋ ൌ௜ ܹܯ

ሻ ݉݋݈ – ܾ݈ܾ/ ݈ሺݐ݊݁݊݋݌݉݋ܿ ݊݁݋ݖ ݏ݃ܽ ݊݋݅ݐݏݑܾ݉݋ܿ ݈ܽݑ݅݀ݒ ݅݊݀݅ ݐ݄݁݅݃ݓ݂ ݋ ݉ݎ݈ܽݑ݈݁ܿ݋ ൌ௞ ܹܯ

ைమܹܯ ሻ݈݋݉ – /݈ܾ32.0 ݈ܾ ሺ ݐ݄݁݅݃ݓ݂ ݋݃݁݊ ݕݔ݋  ݉ݎ݈ܽݑ݈݁ܿ݋ ൌ

ሻ݈݋݉ –28.9 ݈ܾ/݈ܾሺ ݐ݄݁݅݃ݓ݂ ݋ ݎ ܽ݅ ݉ݎ݈ܽݑ݈݁ܿ݋ ൌ௔௜௥ ܹܯ

ሻ݈݋݉ –݈ܾ/݈ܾሺ ݐ݄݁݅݃ݓ݂ ݋ ݐ݋݈݅݌ ݏ ݃ܽ ݉ݎ݈ܽݑ݈݁ܿ݋ ൌ௣௚ ܹܯ

ሻ ݈݉݋ –/݈ܾ ܾ݈ ሺ ݃ܽݏ ݐ݁݊ݒ ݂݋  ݁݅ݓݐ݄݃ ݈ܽ݉ݑ݈݁ܿ݋ݎ ൌ௚ ௩ܹܯ

ሻݏݏ݈݁ݐ݊݅ݑሺ݉ ܾ݈ܶܽ݁ 1 ݋ݎ݂ ݏ݊݀ݑ݋݌݉݋݈ܽ ܿݑ݅݀ݒ݂ ݅݊݀݅݋ ݐݏ݈݅ ൌ ݊

݂ܿݏܷܶ⁄ܤሺ ݊݁݋ݖ݊ ݋݅ݐݏݑܾ݉݋ ܿ ݁ݑ݈ܽݒ݂ ݋݄݁ ݐ  ݅݊݃ݐ ݄݁ܽݐ݊݁ ൌ ௭௖ܸܪܰ

ݏ݂ܿ ܷܶ⁄ܤሺ ݊݀ݑ݋݌݉݋݈ܽ ܿݑ݅݀ݒ ݅݊݀݅ ݁ݑ݈ܽݒ݂ ݋  ݅݊݃ݐ ݄݁ܽ ݊ݐ݁ ൌ ܸܪܰ

ݏ݂ܿ ܷܶ⁄ܤሺ ݐ ݈݅݉݅ݕݐ ݂݈ܾ݈ܽ݉݉ܽ݅݅ݎ݁ݓ݋ ݁ݑ݈ܽݒ ݐ݁݊ݒ ݏ ݈ ݃ܽݐܽ ݅݊݃ݐ ݄݁ܽݐ݊݁ ൌ௅ ி௅ି௚௩

௜

ܸܪܰ

݂ܿݏ⁄ ܤܷܶ ሺ ݊݁݋ݖ݊ ݋݅ݐݏݑܾ݉݋ ܿ ݁ݑ݈ܽݒ݂ ݋݄݁ ݐ  ݅݊݃ݐ ݄݁ܽݐ ݊݁ݐ݅݉݅

ሻ

ሻ

ሻ

ሻ

ൌ ݈ ܰܪܸ௖௭ି௟௜௠௜௧ ሻ

݂ܿݏܷܶ⁄ܤሺ ݁ݑ݈ܽݒ݂ ݋ ݐ݋݈݅݌ ݏ ݃ܽ ݅݊݃ݐ ݄݁ܽݐ݊݁ ൌ௣௚ ܸܪܰ

ሻ ݏ݂ܿ ܷܶ⁄ܤሺ ݁ݑ݈ܽݒ݂ ݋ ݐ݁݊ݒ ݏ ݃ܽ ݅݊݃ݐ ݄݁ܽݐ݊݁ ൌ௚ ௩ܸܪܰ

ሻ݅ܽݏ݌ሺ ݏ݊݁ ݃ܽ݋ݖ ݊݋݅ݐݏݑܾ݉݋݂ ܿ݋  ݌݁ݎݑݏݏ݁ݎ ൌ ௭௖ܲ

݅

ሻ݅ݏ݌14.696 ሺ ݏ݊݋݅ݐ݊݀݋݀ ܿݎܽ݊݀ܽݐݏ ݐ݁ ܽݎݑݏݏ݁ݎ݌  ܽݐܾ݉݁݊ ൌ ௦௧ௗܲ

௜݃݌ ሻ ݂ݎ݊݋݅ݐܽܿ ݈݋ݒሺ ݏ݃ܽ  ݅݊ݐ݋݈݅݌ ݊݋݅ݐܽܿݎ݂ ݉݁ݑ݈݋ݒ݊݀ ݑ݋݌݉݋ܿ ݈ܽݑ݅݀ݒ݊݀݅ ൌ

ሻ݂݄ܿݏሺ  ݕܴܵܵ ܽ݊ ܾܯ  ܿ݁݀ݑ݀݋ݎݐ ݅݊ݎ݅ ݓ݋݁ ݂݈ݐܽݎ݂ ݋ܽ  ݅ܿݎݐ݉݁ݑ݈݋ݒ݈ܽ ݐ݋ݐ ൌ ெௌோௌି௔௜௥ܳ

ሻ݂݄ܿݏሺ  ݓ݋ ݂݈ݎ݋݄݁ ݂ݐ ݐ݁݊ݒ ݏ ݃ܽ ݅ܿݎݐ݉݁ݑ݈݋ݒ ݎ݅ܿ ܽ݅ݎݐ݉݁݋݄݅ܿ݅݋ݐݏ ൌ௚ ௩ି௢௜௔௜௥ ௖௛௦௧ି ܳ

ሻ݂݄ܿݏሺ  ݓ݋݁ ݂݈ݐܽݎ  ݅ܿݎݐ݉݁ݑ݈݋ݒ ݐ݊݁݊݋݌݉݋ ܿ ݐ݁݊ݒ ݏ ݃ܽ ݈݅݀ܽ݅ݒ݊݀݅ ൌ௞ ܳ

ݐ݂ሺ  ݎ݁ܽݐ ݓ ݈݂݋ ݉݁ݎݐ݅ܿ ݑ݈݋ݒ ݐ ݊݁݋݌݉݋݊ܿ ݏ݃ܽ ݐ ݅ݒ݈݁݅݀ܽ݊݀݅ݒ݊ ൌ௔௖௙ ,௞ܳ ଷ ሻݎ/݄

ሻ݂݄ܿݏሺ ݓ݋ ݂݈ݎ݋݄݁ ݂ݐ ݐ݁݊ݒ ݏ ݃ܽ ݅ܿ ݉݁ݎݐ ݑ݈݋ݒ ݃݁ݕݔ݋݊ ݎݐ݅ܿ ݉݁݋݄݅ܿ݅݋ݐݏ ൌ௚ ௩ି௢௜௖௛௦௧ିைଶܳ

ሻ݂݄ܿݏሺ ݓ݋ܽ ݂݈ݎ݁ݐ ݋݅ݎݐ݉݁ݑ݈ܿ ݒ ݃ܽݏ ݐ݁݊ݒ ൌ௚ ௩ܳ

௚௣ܳ ሻ݂݄ܿݏሺ ݓ݋݁ ݂݈ݐܽݎ  ݅ܿݎݐ݉݁ݑ݈݋ݒ ݏ ݃ܽ ݌ݐ݋݈݅ ൌ

௦ܳ ሻ݂݄ܿݏሺ ݓ݋݁ ݂݈ݐܽݎ  ݅ܿݎݐ݉݁ݑ݈݋ݒ  ݏ݁ܽ݉ݐ ൌ

ሻ݂݄ܿݏሺ  ݓ݋݁ ݂݈ݐܽݎ  ݅ܿݎݐ݉݁ݑ݈݋ݒ  ܽݎ݅ ൌ௔௜௥ ܳ

ݐ10.73 ݂ሺ ݐܽ݊ݐݏ݊݋ ܿݏ݃ܽ ൌ ܴ ଷ ) ݋ܴ݈ · ݉ െ ܾ݈ ⁄ ݌ ·ݏ݅

ሻ°ܴሺ  ݊݁݋ݖ ݏ ݃ܽ ݊݋݅ݐݏݑܾ݉݋݂ ܿ݋݁ ݎݑݐܽݎ݁݌݁݉ݐ  ݁ܽݐݑ݈݋ݏܾ ൌ ௭௖ܶ

ሻ528°ܴሺݏ݊݋݅ݐ݊݀݅݋ܿ ݀ݎܽ݊݀ܽݐ ݐ ܽݏ ݁ݎݑݐܽݎ݁݌݁݉ݐ  ݁ܽݐݑ݈݋ݏܾ ൌ ௦௧ௗܶ

ሻ݈݋݈/݉݋݉ሺ ௬ܪ௫ ݎ݁݌݈݁ ݋݂ ݉݋ ܥ ݂݋݊ ݋ܾݎ ܿܽ ݏ݈݁݋݉ ൌ ݔ

ሻ݊݋݅ݐܽܿݎ݂ ݈݋ݒሺ ݏ ݃ܽݐ݁݊ݒ ݄݁ ݅݊ݐ ݊݋݅ݐܽܿݎ݂ ݉݁ݑ݈݋ݒ݊݀ ݑ݋݌݉݋ ܿ ݈ܽ݅ݑ݅݀ݒ݊݀݅ ൌ௜ ݔ

ሻ݊ ݅݋ ݐ ݋݂݈ݎܿܽ ݒሺ ݏ ݄݁ ݅݊ݐ ݐ݁݊ݒ݃ܽ  ݊݋݅ݐܽܿݎ݉݁ ݂ݑ݈݋ݒ݊݀ ݑ݋݌݉݋ܿ ܾ݈݅݁ݐݏݑܾ݉݋ܿ ݈ܽ݅ݑ݅݀ݒ݊݀݅ ൌ௝ ݔ

ሻ݊݋݅ݐܽܿݎ݂ ݈݋ݒሺ ݄݁ݐ ݐ݁݊ݒ ݏ݃ܽ ݅݊ ݈݁݊݁ݕ݌݋ݎ݌ ݂݋݊ ݋݅ݐܽܿݎ݂ ݉݁ݑ݈݋ݒ ൌ௟௘௡௘ ௬௣௥௢௣ݔ

ሻ݈݋݈/݉݋݉ሺ ௬ܪ௫ ݎ݁݌݈݁ ݋݂ ݉݋ ܥ ݃݁݊݋ݎ݀ݕ݂ ݄݋ ݏ݈݁݋݉ ൌ ݕ

6 of 10 
 

 

 

 

 

 

 

 

 

Case 4:13-cv-02009 Document 2-2 Filed in TXSD on 07/10/13 Page 14 of 75 

APPENDIX 1.3 

Table 1 

Individual Compound Properties
 

i

(1) j Compound NHVi 

(Btu/scf) 

MWi 

(lb/lbmol) 

LFLi 

(vol fraction) Cx Hy 

1 1 Hydrogen 274 or 

1212(2) 2.02 0.040 0 2 

2 - Oxygen 0 32.00 ∞ n/a n/a 

3 - Nitrogen 0 28.01 ∞ n/a n/a 

4 - CO2 0 44.01 ∞ n/a n/a 

5 - CO 316 28.01 0.125 n/a n/a 

6 2 Methane 896 16.04 0.050 1 4 

7 3 Ethane 1595 30.07 0.030 2 6 

8 4 Ethylene 1477 28.05 0.027 2 4 

9 5 Acetylene 1404 26.04 0.025 2 2 

10 6 Propane 2281 44.10 0.021 3 8 

11 7 Propylene 2150 42.08 0.024 3 6 

12 8 iso-Butane 2957 58.12 0.018 4 10 

13 9 n-Butane 2968 58.12 0.018 4 10 

14 10 iso-Butene 2928 56.11 0.018 4 8 

15 11 trans-Butene 2826 56.11 0.017 4 8 

16 12 cis-Butene 2830 56.11 0.016 4 8 

17 13 1,3-Butadiene 2690 54.09 0.020 4 6 

18 14 Pentane+ (C5+) 3655 72.15 0.014 5 12 

19 - Water(3) 0 18.02 ∞ n/a n/a 

1

 i=all compounds, j=organic compounds and hydrogen 

2 If using an H2-adjusted NHVvg and NHVcz, then use 1212 BTU/scf for hydrogen. 

3

 A GC does not measure water. If water is measured by means of another 

instrument, the properties of water listed in this row shall be used. 

Note: Benzene is not required to be speciated by the Gas Chromatograph for this 

refinery settlement (see Appendix 1.9) because benzene is present in the Vent Gas 

only in de minimis quantities. Because benzene speciation is not required, it is not 

listed in Table 1of this Appendix. The Vent Gas composition involved in other 

future settlements should be evaluated on a case-by-case basis to determine if 

benzene speciation should be required. 

7 of 10 
 

   

Case 4:13-cv-02009 Document 2-2 Filed in TXSD on 07/10/13 Page 15 of 75 

APPENDIX 1.3 

Table 2 

Combustion Efficiency Multipliers for Steam-Assisted Flares:
 

Variables Based on Minimum Steam Requirements
 

and VOC Concentration in the Vent Gas
 

Minimum VOC Vent Gas A Multiplier B Multiplier* 

Steam Concentration Condition X Condition Y 

≤ 1000 lb/hr ≤ 20.0% 6.45 4.0 0.0 

≤ 1000 lb/hr > 20.0% 6.85 4.0 0.0 

> 1000 lb/hr ≤ 20.0% 7.1 4.0 0.0 

> 1000 lb/hr > 20.0% 7.4 4.0 0.0 

*The B Multiplier used depends on the relationship of hydrogen and propylene in the vent gas as follows: 

Condition X: 3 ≤ H2% ≤ 8 and Propylene% ≥ H2% (all percentages are volume or mole percentages) 

Condition Y: Any condition not meeting the requirements for Condition X. 

Note: The specifications for Condition X are based on the best information available as of the 

Date of Lodging. If new information becomes available thereafter, the parties may modify these 

conditions; any such modification does not constitute a material modification to the Consent 

Decree. 

The “VOC Vent Gas Concentration” shall be calculated on an annual average basis as follows: 

௡

௝ݔ෍ ൌ௚ ௩ܥ

௝ୀସ

 15 Equation 100 כ

Note: The summation does not include methane or ethane. 

8 of 10 
 

Case 4:13-cv-02009 Document 2-2 Filed in TXSD on 07/10/13 Page 16 of 75 

APPENDIX 1.3 

Addendum A 

Verification of Equation 5a and Equation 5b Equivalency
 

In this Appendix, all gaseous flows (i.e, vent gas, steam, pilot gas, and air) may be measured on 

either a mass basis (lb/hr) or a volumetric basis (scfh). Depending on which measurement 

methodology is used, different versions of some equations must be used. These versions are 

designated with an “a” or “b” (e.g. Equation 5a or 5b). In all cases, these equations are 

equivalent. This Addendum demonstrates the equivalence of the two methods for calculating 

NHVcz. 

Equation 5b uses volumetric flow rates for the calculation of NHVcz: 

൯൅ሺܳ௣௚ ܸכܪ ܰ௚௣ ሻ ൫ܳ௩௚ ܸכܪ ܰ ௩௚ ܰܪܸ௖௭ ൌ ܳ௩௚ ൅ ܳ௣௚ ൅ ܳ௦ ൅ ܳ௔௜௥

Equation 5b 

The ideal gas law provides a method for determining volumetric flow rate of a specific gas, k, in 

the combustion zone at standard conditions: 

ܶ௦௧ௗ כ ܲ௖௭ ܳ௞ ൌ ܳ௞,௔௖௙ כ ܲ௦௧ௗ ܶ௖௭

Equation A1 

݉ሶ ܳ௞,௔௖௙ ൌ

݉௞ܴܶ௖௭ ሶ ܳ௞ ൌ ܯܹ௞ܲ௖௭

௞ܴܶ௖௭

௭௖ܲ௞ܹܯ

Equation A2 

ܶ௦௧ௗ כ ܲ௖௭ כ ܲ௦௧ௗ ܶ௖௭݉ሶ ௞ܴܶ௦௧ௗ ൌ ܯܹ௞ܲ௦௧ௗ

Equation A3 

14.696 כ ௞ܹܯ 385.5 ൌ ሶ݉ 528 כ 10.73 כ ௞ ሶ

݉

௞ܹܯ ൌ௞ ܳ

௞

Substitution of this expression into Equation 5b gives NHVcz in terms of mass flow: 

௩௚ ݉ሶ ௣௚ ܸכܪ ܰ ௩௚൰ ൅ ൬385.5 ݉ሶ ൬385.5 ܯܹ௩௚ ܯܹ௚௣

݉ሶ ሶ ሶ ሶ ௩௚ ௣௚ ݉௔௜௥ ൅ 385.5

݉

൅ 385.5

݉

385.5

௥௜௔ܹܯ ுమை

௦

ܹܯ ௚௣ܹܯ ௚௩ܹܯ

Equation A4 

൰ ௣௚ܰ כܪܸ

ܰܪܸ௖௭ ൌ Equation A5

൅ 385.5

Because the combustion zone is well-mixed, each gaseous component of the combustion zone is 

at the same temperature and pressure. Thus, the last expression reduces to Equation 5a: 

9 of 10 
Case 4:13-cv-02009 Document 2-2 Filed in TXSD on 07/10/13 Page 17 of 75 

APPENDIX 1.3 

௔௜௥

݉ሶ ௩௚ ܸܪ ·ܰ ௩௚ ൬ ܯܹ௩௚

݉ሶ ൰൅൬ܯܹ௚௣

݉ሶ ௣௚ ܸܪ ·ܰ ௚௣ ൰൅൬ ܯܹ௚௣

݉ሶ ൰ ൅ ቀ

௥௜௔ܹܯ

൰

ܰܪܸ௖௭ ൌ Equation 5a ݉ሶ ൰൅൬ ݉ሶ ௩௚ ௣௚ ൬ ுమை

௦

ܹܯ ௚௩ܹܯ

This demonstrates the equivalence of Equations 5a and 5b. 

ቁ

10 of 10 
Case 4:13-cv-02009 Document 2-2 Filed in TXSD on 07/10/13 Page 18 of 75 

UNITED STATES
 

v. 

SHELL OIL COMPANY, ET AL. 

APPENDICES TO CONSENT DECREE 

APPENDIX 1.4 

EPA’S POLICY ON EXCESS EMISSIONS DURING 

MALFUNCTIONS, STARTUP, AND SHUTDOWN 
APPENDIX 1.4

POLICY ON EXCESS EMISSIONS DURING MALFUNCTIONS, STARTUP, AND

SHUTDOWN

Introduction

This policy specifies when and in what manner state

implementation plans (SIPS) may provide for defenses to

violations caused by periods of excess emissions due to

malfunctions,l startup, or shutdown. Generally, since SIPS must

provide for attainment and maintenance of the national ambient

air quality standards and the achievement of PSD increments, all

periods of excess emissions must be considered violations.

Accordingly, any provision that allows for an automatic

exemptioh2 for excess emissions is prohibited.

However, the imposition of a penalty for excess emissions

during malfunctions caused by circumstances entirely beyond the

control of the owner or operator may not be appropriate. States

may, therefore, as an exercise of their inherent enforcement

discretion, choose nod to penalize a source that has produced

excess emissions under such circumstances.

This policy provides an alternative approach to enforcement

discretion for areas and pollutants where the respective

contributions of individual sources to pollutant concentrations

in ambient air are such that no single source or small group of

sources has the potential to cause an exceedance of the NAAQS or

PSD increments. Where a single source or small group of sources

has the potential to cause an exceedance of the NAAQS or PSD

increments, as is often the case for sulfur dioxide and lead,'

EPA believes approaches other than enforcement discretion are not

appropriate. In such cases, any excess emissions may have a

significant chance of causing an exceedance or violation of the

applicable standard or PSD increment.

1The term excess emission means an air emission level which

exceeds any applicable emission limitation. Ma3function means a

sudden and unavoidable breakdown of process or control equipment.

2The term automatic exemption means a generally applicable

provision in a SIP that would provide that if certain conditions

existed during a period of excess emissions, then those

exceedances would not be considered violations.

3This policy also does not apply for purposes of PM2.5

NAAQS. In American Trucking Association v. EPA, 175 F. 3d 1027

(D.C. Circ., 1999), the court remanded the PM2.5 NAAQS to the

EPA. The Agency has not determined whether tha.s policy is

appropriate for PM2.5 NAAQS.

Case 4:13-cv-02009 Document 2-2 Filed in TXSD on 07/10/13 Page 19 of 75 
APPENDIX 1.4

- 2 -

Except where a single source or small group of sources has

the potential to cause an exceedance of the NAAQS or PSD

increments, states may include in their SIPS affirmative

defensesg for excess emissions, as long as the SIP establishes

limitations consistent with those set out below. If approved

into a SIP, an affirmative defense would be available to sources

in an enforcement action seeking penalties brought by the state,

EPA, or citizens. However, a determination by the state not to

take an enforcement action would not bar EPA or citizen action s

In addition, in certain limited circumstances, it may be

appropriate for the State to build into a source-specific or

source-category-specific emission standard a provision stating

that the otherwise applicable emission limitations do not apply

during narrowly defined startup and shutdown periods.

I. AUTOMATIC EXEMPTIONS AND ENFORCEMENT DISCRETION

If a SIP contains a provision addressing excess emissions,

i~ cannot be the type that provides for automatic exemptions.

Automatic exemptions might aggravate amba.ent air quality by

excusing excess emissions that cause or contribute to a violation

of an ambient air quality standard. Additional grounds for

disapproving a SIP that includes the automatic exemption approach

are discussed in more detail at 42 Fed. Reg. 58171 (November 8,

1977) and 42 Fed. Reg. 21372 (April 27, 1977). As a result, EPA

will not approve any SIP revisions that provide automatic

exemptions for periods of excess emissions.

The best assurance that excess emissions will not interfere

with NAAQS attainment, maintenance, or increments is to address

excess emissions through enforcement discretion. This policy

provides alternative means for addressing excess emissions of

criteria pollutants. However, this policy does not apply where a

single source or small group of sources has the potential to

cause an exceedance of the NAAQS or PSD increments. Moreover,

'The term affirmative defense means, in the context of an

enforcement proceeding, a response or defense put forward by a

defendant, regarding which the defendant has the burden of proof,

and the merits of which are independently and objectively

evaluated in a judicial or administrative proceeding.

SBecause all periods of excess emissions are violations and

because affirmative defense provisions may not apply in actions

fox injunctive relief, under no circumstances would EPA consa.der

periods of excess emissions, even if covered by an affirmative

defense, to be "federally permiCted releases" under EPCRA or

CERCLA.

Case 4:13-cv-02009 Document 2-2 Filed in TXSD on 07/10/13 Page 20 of 75 
APPENDIX 1.4

- 3 -

nothing in this guidance should be construed as requiring States

to include affirmative defense provisions in their SIPS.

II. AFFIRMATIVE DEFENSES FOR MALFUNCTIONS

The EPA can approve a STP revision that creates an

affirmative defense to claims for penalties in enforcement

actions regarding excess emissions caused by malfunctions as long

as the defense does not apply ~o SIP provisions that derive from

federally promulgated performance standards or emission limits,

such a9 new source performance standards (NSPS) and national

emissions standards for hazardous air pollutants (NESHAPS).6 In

addition, affirmative defenses are not appropriate for areas and

pollutants where a single source or small group of sources has

the potential to cause an exceedance of the NAAQS or PSD

increments. Furthermore, affirmative defenses to claims for

injunctive relief are not allowed. To be approved, an

affirmative defense provision must provide that the defendant has

the burden of proof of demonstrating ghat:

1. The excess emissions were caused by a sudden,

unavoidable breakdown of technology, beyond the control of the

owner or operator;

2. The excess emissions (a) did not stem from any activity

or event that could have been foreseen and avoided, or planned

for, and (b) could not have been avoided by better operation and

maintenance practices;

3. To the maximum extent practicable the air pollution

control equipment or processes were maintained and operated in a

manner consistent with good practice for minimizing emissions;

4. Repairs were made in an expeditious fashion when the

operator knew or should have known that applicable emission

limitations were being exceeded. Off-shift labor and overtime

must have been utilized, to the extent practicable, to ensure

that such repairs were made as expeditiously as practicable;

5. The amount and duration of the excess emissions

(including any bypass) were minimized to the maximum extent

practicable during periods of such emissions;

6To the extent a State includes NSPS ox NESHAPS in its SIP,

the standards should not deviate from those that were federally

promulgated. Because EPA set these standards taking into account

technological limitations, additional exemptions would be

inappropriate.

Case 4:13-cv-02009 Document 2-2 Filed in TXSD on 07/10/13 Page 21 of 75 
APPENDIX 1.4

-~-

6. All possible steps were taken to minimize the impact of

the excess emissions on ambient air quality;

7. All emission monitoring systems were kept in operation

if at all possible;

8. The owner or operator's actions in response to the

excess emissions were documented by properly signed,

contemporaneous operating logs, or other relevant evidence;

9. The excess emissions were n.ot part of a recurring

pattern indicative of inadequate design, operation, or

maintenance; and

10. The owner or operator properly and promptly notified

the appropriate regulatory authority.

The EPA interprets these criteria narrowly. Only those

malfunctions that are sudden, unavoidable, and unpredictable in

nature quality for the defense. For example, a single instance

of a burst pipe that meets the above criteria may qualify under

an affirmative defense. The defense would not be available,

however, if the facility had a history oP similar failures

because of improper design, improper maintenance, or poor

operating practices. Furthermore, a source must have taken all

available measures ~o compensate for and resolve the malfunc~ian.

If a facility has a baghouse fire ghat leads to excess emissions,

the affirmative defense would be appropriate only for the period

of time necessary to modify or curtail operations to come into

compliance. The fire should not be used to excuse excess

emissions generated during an extended period of time while the

operator orders and installs new bags, and relevant SIP language

must limit applicability of the affirmative defense accordingly.

III. EXCESS EMISSIONS DURING STARTUP AND SHTJTDOWN

Tn general, startup and shutdown of process equipment are

part of the normal operation of a source and should be accounted

for in the planning, design, and implementation of operating

procedures for the process and control equipment. Accordingly,

it is reasonable to expect that careful and prudent planning and

design will eliminate violations of emission limitations during

such periods.

A. SOURCE CATEGORY SPECIFIC RULES FOR STARTUP AND SHUTDOWN

For some source categories, given the types of control

technologies available, there may exist short periods of

emissions during startup and shutdown when, despite best efforts

regarding planning, design, and operating procedures, the

Case 4:13-cv-02009 Document 2-2 Filed in TXSD on 07/10/13 Page 22 of 75 
APPENDIX 1.4

- 5 -

otherwise applicable emission limitation cannot be met.

Accordingly, except in the case where a single source or small

group of sources has the potential to cause an exceedance of the

~` NAAQS or P5D increments, it may be appropriate, in consultation

with EPA, to create narrowly-tailored SIP revisions that take

these technological limitations into account and state that the

otherwise applicable emissions limitations do not apply during

narrowly defined startup and shutdown periods. To be approved,

these revisions should meet the following requirements:

1. The revision must be limited to specific, narrowlydefined source categories using specific control strategies

(e.g., cogeneration facilities burning natural gas and using

selective catalytic reduction);

2. Use of the control strategy for this source category

must be technically infeasible during startup or shutdown

periods;

3. The Frequency and duration of operation in startup or

shutdown mode must be minimized to the maximum extent

practicable;

4. As part of its justification of the STP revision, the

state should analyze the potential worst-case emissions that

could occur during startup and shutdown;

5. All possible steps must be taken to minimize the impact

of emissions during startup and shutdown on ambient air quality;

6. At all dimes, the facility must be operated in a manner

consistent with good practice for minimizing emissions, and the

source must have used best efforts regarding planning, design,

and operating procedures to meet the otherwise applicable

emission limitation; and

7. The owner or operator s actions during startup and

shutdown periods must be documented by properly signed,

contemporaneous operating 7.ogs, or other relevant evidence.

B. GENERAL, AFFIRMATIVE DEFENSE PROVISIONS RELATING TO

STARTUP AND SHUTDOWN

In addition to the approach outlined in Section II(A) above,

States may address the problem of excess emissions occurring

during startup and shutdown periods through an enforcement

discretion approach. Further, except in the case where a single

source or small group of sources has the potential to cause an

exceedance of the NAAQS or PSD increments, States may also adopt

for their SIPS an affirmative defense approach. Using this

Case 4:13-cv-02009 Document 2-2 Filed in TXSD on 07/10/13 Page 23 of 75 
~~ APPENDIX 1.4

- 6 -

approach, all periods of excess emissions arising during startup

and shutdown must be treated as violations, and the affirmative

defense provision must not be available for claims for injunctive

relief.. Furthermore, to be approved, such a provision must

provide that the defendant has the burden of proof of

demonstrating that:

1. The periods of excess emissions that occurred during

startup and shutdown were short and infrequent and could not have

been prevented through careful planning and design;

2. The excess emissions were not part of a recurring

pattern indicative of inadequate design, operation, or

maintenance;

3. If the excess emissions were caused'by a bypass (an

intentional diversion of control equipment), then the bypass was

unavoidable to prevent loss of life, personal injury, or severe

property damage;

4. At all times, the facility was operated in a manner

consistent with good practice for minimizing emissions;

5. The frequency and duration of operation in startup or

shutdown mode was minimized to the maximum extent practicable;

6. All possible steps were taken to minimize the impact of

the excess emissions on ambient air quality;

7. A11 emission monitoring systems were kept in operata.on

if at all possible;

8. The owner or operator's actions during the period of

excess emissions were documented by properly signed,

contemporaneous operating logs, or other relevant evidence; and

9. The owner or operator properly and promptly notified the

appropriate regulatory authority.

If excess emissions occur during routine startup or shutdown

periods due to a malfunction, then those instances should be

treated as o~har malfunctions that are subject to the malfunction

provisions of this policy. (Reference Part I above).

bennett899a.wpolAugust 11, 1999

Case 4:13-cv-02009 Document 2-2 Filed in TXSD on 07/10/13 Page 24 of 75 
Case 4:13-cv-02009 Document 2-2 Filed in TXSD on 07/10/13 Page 25 of 75 

UNITED STATES
 

v. 

SHELL OIL COMPANY, ET AL. 

APPENDICES TO CONSENT DECREE 

APPENDIX 1.5 

CALCULATING MOMENTUM FLUX RATIO 
 

Case 4:13-cv-02009 Document 2-2 Filed in TXSD on 07/10/13 Page 26 of 75 

APPENDIX 1.5
	

CALCULATING MOMENTUM FLUX RATIO
	

Momentum Flux Ratio (MFR) is the relationship between the density (ρ) and velocity (v) of the 

Vent Gas plus Center Steam to the density and velocity of the wind. It is defined in Equation 1. 

ଶ

௩௚ା௦,௖௘௡௧ ߩ௩௚ା௦,௖௘௡௧ · ݒ

௥௜௔ݒ · ௥௜௔ߩ ൌ ܴܨܯ

ଶ Equation 1 

The numerator of the fraction is the “momentum flux” of the Vent Gas plus Center Steam and 

the denominator is the “momentum flux” of the air (wind). As the velocity of the wind 

increases, the MFR will decline for a given Vent Gas composition and flow rate. 

Calculations for the density (ρ) components and velocity (v) components are discussed separately 

below. 

Calculating Density 

The general formula to calculate the density of any given component (ρi) at standard temperature 

and pressure (68 °F, 1 atm) is shown in Equation 2. 

௜ ௜ ௜ ൌ ܹܯ ܹܯ ൌ ܹܯ

385.5 ߩ ௜ൌ Equation 2 

From the final form of Equation 2, the density of Ambient Air (ρair), Vent Gas (ρvg), and Center 

Steam (ρs,cent) can be calculated, shown in Equations 3, 4, and 5. 

௥௜௔ܹܯ

ߩ ௥௜௔ൌ 385.5 ൌ 28.96

ܯܹ௩௚ ߩ௩௚ ൌ 385.5

385.5 ൌை 18.02 ܯܹுమ ߩ௦,௖௘௡௧ ൌ

Equation 3 

Equation 4 

Equation 5 

݅ݏ݌ 14.696 · ܲ ·

ܴ · ܶ௔௕௦

°ܴ · ݈݋݈ܾ݉ ሻ68°ܴ ൅ 460°ܴሺ · 10.73 ݐ݂ · ݅ݏ݌ ଷ

ଷ

݈ܾ

385.5 0.075 ൌ ݐ݂

݈ܾ

ݐ݂ ଷ

ଷ

݈ܾ

385.5 0.047 ൌ ݐ݂

1 of 3 
   

   

   

     

   

ሶ ሶ ሶ ሶ

ሶ ሶ

ሶ ሶ

Case 4:13-cv-02009 Document 2-2 Filed in TXSD on 07/10/13 Page 27 of 75 

APPENDIX 1.5 

The density of the Vent Gas plus Center Steam (ρvg+s,cent) is calculated by combining the mass 

flow rates of the Vent Gas and Center Steam and dividing by the combined volumetric flow rates 

of the Vent Gas and Center Steam. This is shown in Equation 6. 

݉௩௚ ൅ ݉௦,௖௘௡௧ ൌ ݉௩௚ ൅ ݉௦,௖௘௡௧

ߩ௩௚ା௦,௖௘௡௧ ൌ ௦,௖௘௡௧

௦,௖௘௡௧

݉

௚௩ ൅ ߩ

௩௚

݉

ߩ

ܳ௩௚ ൅ ܳ௦,௖௘௡௧ Equation 6 

Calculating Velocity 

The velocity of the Vent Gas plus Center Steam (vvg+s,cent) is calculated by Equation 7. 

௦,௖௘௡௧

௦,௖௘௡௧

݉

௚௩ ൅ ߩ

௩௚

݉

ߩ

A௧௜௣ି௨௡௢௕

ܳ௩௚ ൅ ܳ௦,௖௘௡௧

ݒ௩௚ା௦,௖௘௡௧ ൌ ܣ௧௜௣ି௨௡௢௕ൌ Equation 7 

The wind velocity is measured directly. 

Constants: 

݈ܾ

݈݋݈ܾ݉ ൰ 28.96൬ ݎ ܽ݅ ݐ݄݁݅݃ݓ݂ ݋ ݎ݈ܽݑ݈݁ܿ݋݉ ൌ௔௜௥ ܹܯ

݈ܾ

݈݋݈ܾ݉ ൰ ுమܹܯ 18.02൬ ݎ݁ݐܽݓ  ݐ݄݁݅݃ݓ݂ ݋ ݑ݈݁ܿ݋݈݉ݎܽ ൌ ை

௜ܹܯ

ሻ݅ܽݏ݌14.73 ሺ ݁ݎݑݏݏ݁ݎ݌ ݐ݁ ܾܽ݉݅݁݊ݐݑ݈݋ݏܾܽ ൌ ܲ

ଷ

݈ܾ

݂ݐ ൰ ൌ 0.075 ଷ

݈ܾ

൬ ݅ܽݎ ݋݂ ݕݐ ݊݁ݏ݅ ݀ ൌ௔௜௥ ߩ ݐ݂

ଷ

݈ܾ

݂ݐ ൰ ൌ 0.047 ଷ

݈ܾ

൬ ݁ܽ݉ݐ ܵ ݂݋݁ ܥݎ݁ݐ݊ ݀ݕݐ݅ݏ݁݊ ൌ ௧௖௘௡,௦ߩ ݐ݂

ଷݐ

݋݈݈ܾ݉ ൬ ݊݋݌݉݋݁ܿݐ ݅݊ ݐ݄݁݅݃ݓ݂ ݋ ݈݁ܿ݋݉ݎ݈ܽݑ ൌ ݈ܾ

൰

°ܴ · ݈݋݈ܾ݉ ቇ 10.73ቆ ݐܽ݊ݐݏ݊݋ܿ ݏ݃ܽ ൌ ܴ ݂ · ݅ݏ݌

°ܴ 528 ൌ 68°ܴ ൅ 460°ܴ ൌ ሻ°ܴሺ ݁ݎݑݐܽݎ݁݌݁݉ݐ ݐݑ݈݋ݏܾ݁ܽ ൌ ௦௔௕ܶ

2 of 3 
     

       

       

       

       

   

   

   

     

     

     

Case 4:13-cv-02009 Document 2-2 Filed in TXSD on 07/10/13 Page 28 of 75 

APPENDIX 1.5 

Measured variables: 

݈ܾ

݈݈ܾ݋݉ ൰ ൬ ݐ ܸ݁݊ݏܽܩ ݐ݄݁݅݃ݓ݂ ݋ ݑ݈݁ܿ݋݈݉ݎܽ ൌ௚ ௩ܹܯ

݈ܾ

ݎ݄ ൰ ൬ ݁ܽ݉ݐܵ ݎ݁ݐ݁݊ܥ  ݁ݐܽݎ݂ ݋ ݓ݋݂݈ ݏݏ݉ܽ ൌ ௧௖௘௡,௦ ሶ݉

݈ܾ

ݎ݄ ൰ ൬ ݐ ܸ݁݊ݏܽܩ ݁ݐܽݎ݂ ݋ ݓ݋݂݈ ݏݏ݉ܽ ൌ௚ ௩ ሶ݉

௧௖௘௡,௦ܳ ሻ݂݄ܿݏሺ ݁ܽ݉ݐܵ ݁ݐ݁݊ܥݎ ݁ݐܽݎ݂ ݋ ݓ݋݂݈ ݑ݈݋݅ܿ݉ݎݐ݁ ݒ ൌ

௚௩ܳ ሻ݂݄ܿݏሺ ݐ ܸ݁݊ݏܽܩ ݁ݐܽݎ݂ ݋ ݓ݋݂݈ ݐ݉݁ݑ݈݋݅ܿݎ ݒ ൌ

ݐ݂

ݎ݄ ൰ ൬ ݅݊݀ݓ݂ ݋ ݕݐܿ݅݋݈݁ݒ ൌ௔௜௥ ݒ

Calculated variables: 

௕௢௡௨ି௜௣௧ܣ ݐ݂ሺ ݁ݎ ݂݈ܽ݌݅ݐ  ݁ܽݎ݂ ܽ݋ ݏ݋݅ݐ݈ܽ݊݁ܿ െ ݏݏ݋ݎ ܿ ݐݏܾ݋݊ݑݎ݁ݐܿݑ݀ ൌ ሻଶ

ሻ ݊݅ݑݏݏ݈݁ݐ ሺ ݔݑ ݂݈݋݅ݐܽݎ ݉ݑݐ݉݁݊݋݉ ൌ ܴܨܯ

݈ܾ

ݐ݂ ൰ଷ ൬ ݏܽܩ  ݂݋ ݐܸ݁݊ ݕ ݀ݐ݅ݏ݁݊ ൌ௚ ௩ߩ

௜ߩ ݐ݂ ൰ଷ ൬ ݊݋݌݉݋ܿݐ݅݁݊ ݂݋ ݕݐ ݅݀ݏ݁݊ ൌ ݈ܾ

ݐ݂

ݎ݄ ൰ ൬ ݐ ܸ݁݊ݏܽܩ ݂݋ ܿ݋݈݁ݕݐ݅ ݒ ൌ௚ ௩ݒ

ݐ݂

ݎ݄ ൰ ൬ ݁ܽ݉ݐܵ ݁ݐ݁݊ܥݎ ݂݋ ݕݐܿ݅݋݈݁ݒ ൌ ௧௖௘௡,௦ݒ

3 of 3 
Case 4:13-cv-02009 Document 2-2 Filed in TXSD on 07/10/13 Page 29 of 75 

UNITED STATES
 

v. 

SHELL OIL COMPANY, ET AL. 

APPENDICES TO CONSENT DECREE 

APPENDIX 1.6 

CALCULATING THE UNOBSTRUCTED CROSS 

SECTIONAL AREA OF VARIOUS TYPES OF 

FLARE TIPS 
 

 

 

 

 

 

 

 

 

 

 

 

 

Case 4:13-cv-02009 Document 2-2 Filed in TXSD on 07/10/13 Page 30 of 75 APPENDIX 1.6 

Type II 

Exit Lower 

Steam/Air 

Tubes 

Pilot 

Steam/Air 

Tubes 

O.D. T 

Stability Ring 

I.D.T 

I.D.T 

Atip-unob = (I.D.T)2/4 – AST – NT * *(O.D.T)2 ~ /4

Example: 

Where: Atip-unob = Unobstructed Cross 

Sectional Area of Flare Tip 

I.D.T = Inside Diameter Flare Tip 

XT = Number of Stability Tabs 

AST = Area of a Stability Tab 

I.D.T = 41.5 inches 

XT = 3 

AST = 3 Sq. inches 

Atip-unob = (41.5)2 ~ /4 - (3 * 3) 

Example: 

Where: Atip-unob = Unobstructed Cross 

Sectional Area of Flare Tip 

I.D.T = Inside Diameter Flare Tip 

AST = Area of Stability Ring 

O.D.T = Outside Diameter of 

...........Steam/Air Tubes 

NT = Number of Steam/Air Tubes 

I.D.T = 47.5 inches 

AST = 100 Sq. inches 

O.D.T = 6.5 inches 

NT = 8 

Atip-unob = (47.5)2/4 - 100 - 8* *(6.5)2 ~ ~ /4

A Atip-unob = 1322 Sq. inches tip-unob = 1344 Sq. inches 

Type I 

Pilot Stability Tab 

I.D.T 

I.D.T 

Atip-unob = (I.D.T)2/4-(XT*AST ~ ) ~ 
 

 

 

 

 

 

 

 

 

 

Case 4:13-cv-02009 Document 2-2 Filed in TXSD on 07/10/13 Page 31 of 75 APPENDIX 1.6 

Example: 

Where: 

Example: 

Atip-unob = Unobstructed Cross Sectional Area Where: 

of Flare Tip 

I.D.M = Inside Diameter of One Tip Module 

NM = Number of Modules 

XT = Number of Stability Tabs per Module 

AST = Area of a Stability Tab 

I.D.M = 17 inches 

NM = 6 XT = 3 

AST = 3 Sq. inches 

Atip-unob = 6 * ( *(17)2 ~ /4 – 3 * 3) 

Atip-unob = 1308 Sq. inches 

Atip-unob = Unobstructed Cross 

Sectional Area of Flare Tip 

I.D.T = Inside Diameter of Flare Tip 

I.D.T = 41.5 inches 

Atip-unob = (41.5)2/4 

Atip-unob = 1353 Sq. inches 

~ 

Type IV 

I.D.T 

I.D.T 

Pilot 

Atip-unob = (I.D.T)2 ~ /4

Type III 

Pilot 

I.D.M 

Atip-unob = NM * ( *(I.D.M)2/4 – XT * AST ~ )

I.D.M 

Stability Tabs 

Modules 
Case 4:13-cv-02009 Document 2-2 Filed in TXSD on 07/10/13 Page 32 of 75 

UNITED STATES
 

v. 

SHELL OIL COMPANY, ET AL. 

APPENDICES TO CONSENT DECREE 

APPENDIX 1.7 

DEPICTION OF GASES ASSOCIATED WITH 

STEAM-ASSISTED FLARES 
Case 4:13-cv-02009 Document 2-2 Filed in TXSD on 07/10/13 Page 33 of 75 DEPICTION OF GASES ASSOCIATED
 

WITH STEAM-ASSISTED FLARES
 

OPERATIONAL WASTE REGULATORY GASES GASES GASES AND STEAM 

VOC-CREATING METHANE NON - ALL SUPPLEMENTAL SWEEP PURGE PILOT STEAM

HYDROCARBONS AND HYDROCARBON OTHER GAS GAS GAS GAS (HCs) ETHANE HAPs 

GASES THAT 

MAY AFFECT 

COMBUSTION 

EFFICIENCY 

NON-HC, 

NON-HAP, 

CARBONS 

(eg, CO2, CO) 

ALL OTHER 

(Including Steam 

(water) in the 

Waste Gas) 

HYDROGEN 

(H2

) 

NITROGEN 

(N2

) 

CONSENT DECREE 

DEFINITIONS 

WASTE GAS 

“The mixture of all gases from facility operations 

that is directed to a flare for the purpose of disposing 

of the gases.” 

However, if a facility has instrumentation capable of calculating 

the flow rate of H2

, N2, O2, CO, CO2, and/or H2O in the Waste Gas, 

the contribution of all calculated flows of these elements/compounds 

may be excluded from Waste Gas flow rate calculations. 

VENT GAS 

“The mixture of all gases found prior to the flare tip. 

This includes all Waste Gas, Supplemental Gas, 

Sweep Gas, and Purge Gas.” 

APPENDIX 1.7 COMBUSTION ZONE GAS 

“The mixture of all gases and steam found just after

 the flare tip. This includes all Vent Gas, Pilot Gas, 

and Total Steam.” 
Case 4:13-cv-02009 Document 2-2 Filed in TXSD on 07/10/13 Page 34 of 75 

UNITED STATES
 

v. 

SHELL OIL COMPANY, ET AL. 

APPENDICES TO CONSENT DECREE 

APPENDIX 1.8 

OUTLINE OF REQUIREMENTS FOR THE FLARE 

DATA AND INITIAL MONITORING SYSTEMS 

REPORT 
 

 

 

 

 

 

 

 

Case 4:13-cv-02009 Document 2-2 Filed in TXSD on 07/10/13 Page 35 of 75 

APPENDIX 1.8 

OUTLINE OF REQUIREMENTS FOR THE
	

FLARE DATA AND INITIAL MONITORING SYSTEMS REPORT
	

1. Facility-Wide 

1.1 Facility plot plan showing the location of each flare in relation to the general plant 

layout 

2. General Description of Flare 

2.1 Ground or elevated 

2.2 Type of assist system
 

2.3 Simple or integrated (e.g., sequential, staged) 

2.4 Date first installed 

2.5 History of any physical changes to the Flare 

2.6 Whether the Flare is a Temporary-Use Flare, and if so, the duration and time 

periods of use 

2.7 Flare Gas Recovery System (“FGRS”), if any, and date first installed 

3. Flare Components: Complete description of each major component of the Flare, except 

the Flare Gas Recovery System (see Part 5), including but not limited to: 

3.1 Flare stack (for elevated flares) 

3.2 Flare tip 

3.1.2.1 Date installed 

3.1.2.2 Manufacturer 

3.1.2.3 Tip Size 

3.1.2.4 Tip Drawing 

3.3 Knockout or surge drum(s) or pot(s), including dimensions and design capacities 

3.4 Water seal(s), including dimensions and design parameters 

3.5 Flare header(s) 

3.6 Sweep Gas system
 

3.7 Purge gas system
 

3.8 Pilot gas system
 

3.9 Supplemental gas system

 3.10 Assist system

 3.11 Ignition system
 

4. Simplified process diagram(s) showing the configuration of the components listed in 

Paragraph 3 

1 of 3 
 

 

 

 

 

 

 

 

 

 

 

 

 

 

Case 4:13-cv-02009 Document 2-2 Filed in TXSD on 07/10/13 Page 36 of 75 

APPENDIX 1.8
	

5. Existing Flare Gas Recovery System (“FGRS”) 

5.1 Complete description of each major component, including but not limited to: 

5.1.1 Compressor(s), including design capacities 

5.1.2 Water seal(s), rupture disk, or similar device to divert the flow 

5.2 Maximum actual past flow on an scfm basis and the annual average flow in scfm
 

for the five years preceding Date of Lodging 

5.3 Simplified schematic showing the FGRS 

5.4 Process Flow Diagram that adds the FGRS to the PDF(s) in Part 4 

6. Flare Design Parameters 

6.1 Maximum Vent Gas Flow Rate and/or Mass Rate 

6.2 Maximum Sweep Gas Flow Rate and/or Mass Rate 

6.3 Maximum Purge Gas Flow and/or Mass Rate, if applicable 

6.4 Maximum Pilot Gas Flow and/or Mass Rate 

6.5 Maximum Supplemental Gas Flow Rate and/or Mass Rate 

6.6 If steam-assisted, Minimum Total Steam Rate, including all available information 

on how that Rate was derived 

7. Gases Venting to Flare 

7.1. Sweep Gas 

7.1.1 Type of gas used 

7.1.2 Actual set operating flow rate (in scfm) 

7.1.3 Average lower heating value expected for each type of gas used 

7.2 Purge Gas, if applicable 

7.2.1 Type of gas used 

7.2.2 Actual set operating flow rate (in scfm) 

7.2.3 Average lower heating value expected for each type of gas used 

7.3 Pilot Gas 

7.3.1 Type of gas used 

7.3.2 Actual set operating flow rate (in scfm) 

7.3.3 Average lower heating value expected for each type of gas used 

7.4 Supplemental Gas 

7.4.1 Type of gas used 

7.4.2 Average lower heating value expected for each type of gas used 

7.5 Steam (if applicable) 

7.5.1 Drawing showing points of introduction of Lower, Center, Upper, and any 

other steam
 

7.6 Simplified flow diagram that depicts the points of introduction of all gases, 

including Waste Gases, at the Flare (in this diagram, the detailed drawings of 

7.5.1 may be simplified; in addition, detailed Waste Gas mapping is not required; 

a simple identification of the header(s) that carries(y) the Waste Gas to the Flare 

and show(s) its(their) location in relation to the location of the introduction of the 

other gases is all that is required) 

2 of 3 
 

 

 

 

 

 

Case 4:13-cv-02009 Document 2-2 Filed in TXSD on 07/10/13 Page 37 of 75 

APPENDIX 1.8
	

8. Existing Monitoring Systems 

8.1 A brief narrative description, including manufacturer and date of installation, of 

all existing monitoring systems, including but not limited to: 

8.1.1 Waste Gas and/or Vent Gas flow monitoring 

8.1.2 Waste Gas and/or Vent Gas heat content analyzer 

81.3 Sweep Gas flow monitoring 

8.1.4 Purge Gas flow monitoring 

8.1.5 Supplemental Gas flow monitoring 

8.1.6 Steam flow monitoring 

8.1.7 Waste Gas or Vent Gas molecular weight analyzer 

8.1.8 Gas Chromatograph 

8.1.9 Sulfur analyzer(s) 

8.1.10 Video camera 

8.1.11 Thermocouple 

8.2 Drawing(s) showing locations of all existing monitoring systems 

9. Monitoring Equipment to be Installed to Comply with Consent Decree 

10. Narrative Description of the Monitoring Methods and Calculations that will be used to 

comply with the NHVCZ, S/VG, and MFR Requirements in the Consent Decree 

11. Identification of Calibration Gases to be used to comply with Appendix 1.10 

3 of 3 
Case 4:13-cv-02009 Document 2-2 Filed in TXSD on 07/10/13 Page 38 of 75 

UNITED STATES
 

v. 

SHELL OIL COMPANY, ET AL. 

APPENDICES TO CONSENT DECREE 

APPENDIX 1.9 

LIST OF COMPOUNDS A GAS 

CHROMATOGRAPH MUST BE CAPABLE OF 

SPECIATING 
 

 

Case 4:13-cv-02009 Document 2-2 Filed in TXSD on 07/10/13 Page 39 of 75 

APPENDIX 1.9 

LIST OF COMPOUNDS A GAS CHROMATOGRAPH 

MUST BE CAPABLE OF SPECIATING 

The Gas Chromatograph must be capable of speciating the Vent Gas into the following: 

1.	 Hydrogen 

2.	 Oxygen 

3.	 Nitrogen 

4.	 Carbon Dioxide 

5.	 Carbon Monoxide 

6.	 Methane 

7.	 Ethane 

8.	 Ethene (aka: Ethylene) 

9.	 Acetylene 

10.	 Propane 

11.	 Propene (aka: Propylene) 

12.	 2-Methylpropane (aka: iso-Butane) 

13.	 Butane (aka: n-Butane) 

14.	 But-1-ene (aka: butene, alpha-butylene) and 2-methylpropene (aka: 

iso-butylene, iso-butene) (these two constituents will be measured on the 

same column and the reported result will be one value: the sum of the two 

constituents) 

15.	 E-but-2-ene (aka: beta-butylene, trans-butene) 

16.	 Z-but-2-ene (aka: beta-butylene, cis-butene) 

17.	 1,3 butadiene 

18.	 Pentane plus (aka: C5 plus) (i.e., all HCs with five Cs or more) 

19.	 Hydrogen Sulfide 

Outputs from the Gas Chromatograph shall be on a mole percent basis except for Hydrogen 

Sulfide which will be on a parts per million basis. 

1 of 1 
Case 4:13-cv-02009 Document 2-2 Filed in TXSD on 07/10/13 Page 40 of 75 

UNITED STATES
 

v. 

SHELL OIL COMPANY, ET AL. 

APPENDICES TO CONSENT DECREE 

APPENDIX 1.10 

EQUIPMENT AND INSTRUMENTATION 

TECHNICAL SPECIFICATIONS AND QUALITY 

ASSURANCE/QUALITY CONTROL 

REQUIREMENTS 
Case 4:13-cv-02009 Document 2-2 Filed in TXSD on 07/10/13 Page 41 of 75 

APPENDIX 1.10
 

EQUIPMENT AND INSTRUMENTATION TECHICAL SPECIFICATIONS
 

AND QUALITY ASSURANCE/QUALITY CONTROL REQUIREMENTS
 

I. VENT GAS FLOW METER 

a. Velocity Range: 0.1–250 ft/sec 

b. Repeatability: ± 1% of reading over the velocity range 

c. Design Accuracy: ± 5% initially to 40%, 60%, and 90% of monitor full scale as 

certified by the manufacturer 

d. Operational Accuracy: ± 20% of reading over the velocity range of 0.1–1 ft/s and 

± 5% of reading over the velocity range of 1–250 ft/s 

e. Installation: Applicable AGA, ANSI, API, or equivalent standard 

f.	 Flow Rate Determination: Must be corrected to one atmosphere pressure and 

68 °F 

g. QA/QC: Annual calibration shall be conducted. 

h. Pressure and Temperature Sensors: See Part IV below. 

II. VENT GAS AVERAGE MOLECULAR WEIGHT ANALYZER 

(may be part of the Vent Gas Flow Meter) 

a. Molecular Weight Range and Accuracy: 

i. Range: 0 to 60 gr/grmol 

ii. Accuracy: ± 1.2 gr/grmol if a Vent Gas Flow Meter or BTU analyzer that 

monitors the flare is capable of continuously analyzing Molecular 

Weight; 

± 3.0 gr/grmol if and only if: (i) the Vent Gas Flow Meter that 

monitors the flare is not capable of continuously analyzing 

Molecular Weight; (ii) there is no BTU Analyzer that monitors the 

flare or the BTU Analyzer is not capable of continuously analyzing 

Molecular Weight; and (iii) a Gas Chromatograph is used for the 

purpose of continuously analyzing Molecular Weight 

1 of 5 
 

Case 4:13-cv-02009 Document 2-2 Filed in TXSD on 07/10/13 Page 42 of 75 

APPENDIX 1.10
 

III. STEAM FLOW METER 

a. Repeatability: ± 1% of reading over the range of the instrument 

b. Accuracy: ± 1% full scale on a volumetric basis 

± 2.5% full scale on a mass basis 

c. Installation: Applicable AGA, ANSI, API, or equivalent standard 

d. Flow Rate Determination: Must be corrected to one atmosphere pressure and 

68 °F 

e. QA/QC: Annual calibration shall be conducted. 

f. Pressure and Temperature Sensors: See Part IV below. 

IV. VENT GAS AND STEAM FLOW METERS: PRESSURE AND TEMPERATURE 

SENSORS 

a. Temperature monitor must be calibrated annually to ± 5%. 

b. Pressure monitor must be calibrated annually to within ± 5%. 

V. GAS CHROMATOGRAPH (“GC”)

 A. General 

a. Accuracy: The gas chromatography system shall be maintained to be 

accurate within 5% of full scale. 

b. 8-Hour Repeatability: ± 1.0% of full scale on a volumetric basis over the 

full range 

c. The minimum sampling frequency shall be one sample every 15 minutes. 

d. The GC shall be capable of speciating all gas constituents listed in 

Appendix 1.9. 

e. The sampling system sample line shall be heat traced and maintained at no 

lower than 135 degrees Fahrenheit with no cold spots. The sampling 

cabinet shall be maintained at no lower than 125 degrees Fahrenheit. All 

system components shall be heated, including the probe external to the 

flare piping, calibration valve, sample lines, sampling loop (or sample 

introduction system), and GC oven. 

2 of 5 
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APPENDIX 1.10
 

f. Where technically feasible, the sampling location should be at least two 

equivalent duct diameters downstream from the nearest control device, 

point of pollutant generation, or other point at which a change in the 

pollutant concentration or emission rate occurs. The location should not 

be close to air in-leakages. Where technically feasible, the location should 

also be at least 0.5 diameters upstream from the exhaust or control device. 

B. Gas Chromatograph Calibration Standards 

1. Net Heating Value and Analyte Measurements. For the Net Heating 

Value and Analyte measurements, the GC shall be operated and 

maintained in accordance with Performance Specification 9 (“PS9”) of 

Appendix B of 40 C.F.R. Part 60 except: 

a. Daily Validation Procedure. Instead of the daily mid-level 

validation procedure in Section 10.2 of PS9, a daily low-level 

validation procedure shall be conducted on the calculated Net 

Heating Value of a certified calibration gas mixture that is 

developed using the concentration of each analyte specified in 

Column 1 of Table 1 below. The average instrument response 

shall not vary by more than 10 percent from the Net Heating Value 

of the certified calibration gas mixture. 

b. Quarterly Validation Procedure. The multi-point calibration error 

check procedure in Section 10.1 of PS9 shall be conducted 

quarterly for the analytes listed in Subparagraph V.B.1.c below. 

No calibrations will be required after routine maintenance or repair 

where such activities do not have the potential to alter the sampling 

or analysis of the gas. The GC must meet the calibration 

performance criteria in Sections 13.1 and 13.2 of PS9 for the listed 

analytes, such that: (i) the average instrument response must not 

differ by more than 10 percent of each analyte calibration gas 

value; and (ii) the precision and linearity check of each analyte 

listed below shall not deviate by more than 5 percent from the 

average concentration measured. 

c. The analytes to be used are: 

i. Hydrogen 

ii. Nitrogen 

iii. Methane 

iv. Ethane 

v. Propane 

vi. Propylene 

vii. Ethylene 

3 of 5 
Case 4:13-cv-02009 Document 2-2 Filed in TXSD on 07/10/13 Page 44 of 75 

APPENDIX 1.10 

d. The calibration gas mixtures may be set by the procedures 

identified in Section 7.1 of PS9 or may be within 10 percent of the 

concentration values listed in Table 1. The gases must be certified 

to ± 2 percent. 

Table 1: Calibration Gas Mixtures for Net Heating Value Calibrations/Validations(1) 

Component Daily 

Low-Level 

Gas 

(Col. 1) 

Quarterly 

Low-Level Gas 

(Col. 2) 

Quarterly 

Mid-Level 

Gas 

(Col. 3) 

Quarterly 

High-Level Gas 

(Col. 4) 

Hydrogen 8 8 30 12 

Nitrogen 65 65 8 5 

Methane 22 22 48 30 

Ethane 2 2 3 30 

Propane 1 1 2 15 

Propylene 1 1 8 5 

Ethylene 1 1 1 3 

NHV (Btu/scf) 

Unadjusted for 

H2 

310 310 793 1273 

(1) The individual analytes are in volume percent. 

2. H2S Measurement. For the H2S measurement, the GC shall be operated 

and maintained in accordance with Performance Specification 7 of 

Appendix B of 40 C.F.R. Part 60. Quality assurance procedures set forth 

in Appendix F of 40 C.F.R. Part 60 shall be followed. The span shall be 

set at 300 ppmv H2S or as required by NSPS Subpart Ja, if different. 

VI. Calculation of Instrument Downtime 

1. For purposes of calculating the 110 hours per calendar quarter of instrument 

downtime allowed pursuant to Paragraphs 28 and 60.a for SDP’s Regular-Use 

Flares and for purposes of calculating the 5% of instrument downtime allowed 

pursuant to Paragraphs 28 and 60.b for SDP’s Temporary-Use Flares, the time 

used for GC calibration and validation activities required by Subparagraph V.B.1 

of this Appendix may be excluded. 

2. Any hour that meets the requirements of 40 C.F.R. § 60.13(h)(2) shall not be 

counted toward instrument downtime. Specifically: 

(i) For a full operating hour (any clock hour where the flare is In Operation 

(i.e., Capable of Receiving Sweep, Supplemental, and/or Waste Gas) for 

60 minutes), if there are at least four valid data points to calculate the 

4 of 5 
Case 4:13-cv-02009 Document 2-2 Filed in TXSD on 07/10/13 Page 45 of 75 

APPENDIX 1.10
 

hourly average (that is, one data point in each of the 15-minute quadrants 

of the hour), then there is no period of instrument downtime; 

(ii) For a partial operating hour (any clock hour where the flare is In 

Operation (i.e., Capable of Receiving Sweep, Supplemental, and/or Waste 

Gas) for less than 60 minutes), if there is at least one valid data point in 

each 15-minute quadrant of the hour in which the flare is In Operation 

(i.e., Capable of Receiving Sweep, Supplemental, and/or Waste Gas) to 

calculate the hourly average, then there is no period of instrument 

downtime; and 

(iii) For any operating hour in which required maintenance or 

quality-assurance activities on the instruments or monitoring systems 

associated with the flare are performed: 

(A) If the flare is In Operation (i.e., Capable of Receiving Sweep, 

Supplemental, and/or Waste Gas) in two or more quadrants of the 

hour and if there are at least two valid data points separated by at 

least 15 minutes to calculate the hourly average, then there is no 

period of instrument downtime; or 

(B) If the flare is In Operation (i.e., Capable of Receiving Sweep, 

Supplemental, and/or Waste Gas) in only one quadrant of the hour 

and if there is at least one valid data point to calculate the hourly 

average, then there is no period of instrument downtime. 

5 of 5 
Case 4:13-cv-02009 Document 2-2 Filed in TXSD on 07/10/13 Page 46 of 75 

UNITED STATES
 

v. 

SHELL OIL COMPANY, ET AL. 

APPENDICES TO CONSENT DECREE 

APPENDIX 1.11 

WASTE GAS MAPPING: LEVEL OF DETAIL 

NEEDED TO SHOW MAIN HEADERS AND 

PROCESS UNIT HEADERS 
Case 4:13-cv-02009 Document 2-2 Filed in TXSD on 07/10/13 Page 47 of 75 

APPENDIX 1.11 

WASTE GAS MAPPING: 

LEVEL OF DETAIL NEEDED TO SHOW MAIN HEADERS
 

AND PROCESS UNIT HEADERS
 

Purpose: 

Waste Gas Mapping is required in order to identify the source(s) of waste gas entering 

each Covered Flare. Waste Gas Mapping can be done using instrumentation, isotopic 

tracing, acoustic monitoring, and/or engineering estimates for all sources entering a 

flare header (e.g. pump seal purges, sample station purges, compressor seal nitrogen 

purges, relief valve leakage, and other sources under normal operations). This 

Appendix outlines what needs to be included as the Waste Gas Mapping section within 

the Initial Waste Gas Minimization Plan (“Initial WGMP”) 

Waste Gas Mapping Criteria: 

For purposes of waste gas mapping, a main header is defined as the last pipe segment 

prior to the flare knock out drum. Process unit headers are defined as pipes from inside 

the battery limits of each process unit that connect to the main header. For process unit 

headers that are greater than or equal to six (6) inches in diameter, flow (“Q”) must be 

identified and quantified if it is technically feasible to do so. In addition, all sources 

feeding each process unit header must be identified and listed in a table, but not 

necessarily individually quantified. For process unit headers that are less than six (6) 

inches in diameter, sources must be identified, but they do not need to be quantified. 

Waste Gas Mapping Submission Requirements: 

For each Covered Flare, the following shall be included within the Waste Gas Mapping 

section of the Initial WGMP: 

1. Simplified Schematic consistent with the example schematic included on the second 

page of this Appendix. 

2. Table of all sources connected to each flare main header and process unit header 

consistent with the Table included on the third page of this Appendix. 

1 of 3 
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2 of 3
Case 4:13-cv-02009 Document 2-2 Filed in TXSD on 07/10/13 Page 49 of 75 

Table 1: Example of Flare Source Description Table 

Process Unit Header 

Sources Detailed Source Description 

QPH1 

(Ex: FCCU Gas Con Unit) 

3 PSVs PSV-14 on 110-D-5 Gas Con Absorber 

PSV-12 on 110-D-1 Amine Scrubber PSV-7 on 110-F-1 Batch Caustic Vessel 

2 Pump Seal Purges 110-G-1 LPG Pump 

110-G-2 Rich Amine Pump 

1 Sample Station 110-S-1 LPG 1 PSV PSV 17 on 112-D-1 Main Column 1 Pressure Control Valve 

PCV 21 – Emergency Wet Gas Compressor 

1 PSV PSV-21 on Flush Oil Drum 1 Pump Seal Purge 110-G-23 Slurry Oil Pump 

QPH2 (Ex: Gas Oil Treater) 

Continue same as PH1 Continue same as PH1 

QPH3 Continue same as PH1 Continue same as PH1 

QPH4 Continue same as PH1 Continue same as PH1 A-H 1 PSVs PSV-17 on 109-E-42 Slurry Heat Exchanger 

B-H 2 Pump Seal Purges 110-G-3 Gas Oil Feed 

110-G-4 Main Column Reflux 

3 of 3 
Case 4:13-cv-02009 Document 2-2 Filed in TXSD on 07/10/13 Page 50 of 75 

UNITED STATES
 

v. 

SHELL OIL COMPANY, ET AL. 

APPENDICES TO CONSENT DECREE 

APPENDIX 1.12 

REPRESENTATIONS OF DISCONTINUOUS 

WAKE DOMINATED FLOW 
 

Case 4:13-cv-02009 Document 2-2 Filed in TXSD on 07/10/13 Page 51 of 75 

APPENDIX 1.12 

REPRESENTATIONS OF DISCONTINUOUS WAKE DOMINATED FLOW 

Definition 

“Discontinuous Wake Dominated Flow” shall mean gas flow exiting a Flare tip that is identified 

visually by: 

i. The presence of a flame that is: (1) immediately adjacent to the 

exterior of the Flare tip body; and (2) below the exit plane of the Flare tip; and 

ii. A discontinuous flame, such that pockets of flame are detached from 

the portion of the flame that is immediately adjacent to the exterior of the Flare tip body. 

Background 

The gases present just outside of the flare tip are influenced by several factors. All of these 

factors are present all of the time, but as process and environmental conditions change, the 

relative “strength” of each factor will change. The most dominant factors will dictate the flow of 

the Vent Gases, i.e., will determine the size, shape, and direction of the flame. Some of the 

influences on the Vent Gases are: 

o	 The low pressure region, or wake, that is downwind and next to the flare. 

o	 The temperature gradient that causes the warm combustion gases to be buoyant, 

or rise. 

o	 The inertia, or resistance to changes in speed and direction, of the Vent Gases as 

they exit the tip. 

The regimes below show how a flame will appear when the most dominant influences are, 

respectively, the wake, the buoyancy due to temperature, and the inertia due to the gas’s 

momentum. 
     

Case 4:13-cv-02009 Document 2-2 Filed in TXSD on 07/10/13 Page 52 of 75 

APPENDIX 1.12
	

Flare Tip

Flare Tip

Images take from: Practical Implications of Prior Research on Today’s Outstanding Flare 

Emissions Questions and a Research Program to Answer Them 

James Seebold, ChevronTexaco (Retired)
 

Peter Gogolek, Natural Resources Canada
 

John Pohl, Virginia Polytechnic Institute and State University
 

Robert Schwartz, John Zink Company LLC 

As a wake dominated flame becomes less stable, it becomes segmented, or discontinuous. The 

following is a representation of “Discontinuous Wake Dominated Flow.” The red area is an 

artist’s rendition of a flame. 

2 of 4
     

Case 4:13-cv-02009 Document 2-2 Filed in TXSD on 07/10/13 Page 53 of 75 

APPENDIX 1.12
	

The following image represents a flame below the plane of the exit of the flare tip. However, 

since the flame is not discontinuous and not immediately adjacent to the tip, this image would 

not represent Discontinuous Wake Dominated Flow. 

The following image represents a flame below the plane of the exit of the flare tip and attached 

to the tip. However, since the flame is not discontinuous, this image would not represent 

Discontinuous Wake Dominated Flow. 

3 of 4
     

Case 4:13-cv-02009 Document 2-2 Filed in TXSD on 07/10/13 Page 54 of 75 

APPENDIX 1.12
	

In order for the flame to be deemed discontinuous, it should be segmented, and not merely 

possess small pockets of flame at the outer boundary of a single large cohesive flame. 

Furthermore, a discontinuous flame will normally appear thin relative to its length, and lack a 

single bulbous core. The following image represents a flame with a small pocket of flame only 

at the outer edges of the broad main flame. This would not represent a discontinuous flame, and 

therefore would not be Discontinuous Wake Dominated Flow. 

4 of 4
Case 4:13-cv-02009 Document 2-2 Filed in TXSD on 07/10/13 Page 55 of 75 

UNITED STATES
 

v. 

SHELL OIL COMPANY, ET AL. 

APPENDICES TO CONSENT DECREE 

APPENDIX 1.13 

CALCULATING THE AMOUNT OF STIPULATED 

PENALTIES DUE FOR VIOLATING 

LIMITATIONS OF FLARING WHEN THE 

STIPULATED PENALTIES ARE BASED ON 

EXCESS VOCS AND SO2 EMITTED
	
 

 

 

 

 

 

 

 

 

 

 

 

Case 4:13-cv-02009 Document 2-2 Filed in TXSD on 07/10/13 Page 56 of 75 

APPENDIX 1.13 

CALCULATING THE AMOUNT OF STIPULATED PENALTIES DUE 

FOR VIOLATING LIMITATIONS ON FLARING
	

WHEN THE STIPULATED PENALTIES ARE BASED ON 

EXCESS VOCs AND SO2 EMITTED
	

I. Stipulated Penalties for Violating the 30-Day Rolling Average Limit. The following 

equation shall be used to calculate the amount of stipulated penalties due for violating the 30-day 

rolling average limit on flaring: 

n

 Penalty due = ∑ [$$30d,VOC x EE30d,VOC] + [$$30d,SO2 x EE30d,SO2] (Eq. 1)

 i=1

 Where: 

n = Each day the 30-day rolling average limit is exceeded 

$$30d,VOC = Dollars per ton of VOC for violating the 30-day limit 

($300/ton because SDP Refinery is in an ozone 

 nonattainment area)

 EE30d,VOC = 30-day average VOC emissions above the flow limit on day limit 

 is violated; see Equation 3.a 

$$30d,SO2 = Dollars per ton of SO2 for violating 30-day limit ($100/ton) 

EE30d,SO2 = 30-day average SO2 emissions above the flow limit on day limit is 

 violated; see Equation 4.a 

II. Stipulated Penalties for Violating the 365-day Rolling Average Limit. The following 

equation shall be used to calculate the amount of stipulated penalties due for violating the 

365-day rolling average limit on flaring: 

n

 Penalty due = ∑ [$$365d,VOC x EE365d,VOC] + [$$365d,SO2 x EE365d,SO2] (Eq. 2)

 i=1

 Where: 

n = Each day the 365-day rolling average limit is exceeded

 $$365d,VOC = Dollars per ton of VOC for violating 365-day limit 

($120/ton because SDP Refinery is in an ozone 

 nonattainment area) 

EE365d,VOC = 365-day average VOC emissions above the flow limit on day limit 

 is violated; see Equation 3.b 

$$365d,SO2 = Dollars per ton of SO2 for violating 30 day cap ($40/ton) 

EE365d,SO2 = 365-day average SO2 emissions above the flow limit on day limit 

 is violated; see Equation 4.b 

1 of 4 
 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Case 4:13-cv-02009 Document 2-2 Filed in TXSD on 07/10/13 Page 57 of 75 

APPENDIX 1.13 

III. Calculating Average Emissions of VOCs Above the Flow Limit When Violating the 

30-Day and 365-Day Rolling Average Limit 

A. Violating the 30-day rolling average limit. The following equation shall be 

used to calculate the 30-day average VOC emissions above the flow limit for the day that the 

30-day rolling average limit is violated: 

EE30d,VOC = [Q30d,actual – Q30d,allowable][VOC30d,vol fraction] [.0026] [MW30d,VOC] [.0005][1 - CE30d,as 

fraction] (Eq. 3.a) 

Where: 

EE30d,VOC = 30-day average VOC emissions above the flow limit on the day 

 that the 30-day rolling average limit is violated, in tons per day 

Q30d,actual = Actual 30-day rolling average Waste Gas Flow Rate on the day 

 that the 30-day rolling average limit is violated, in scfd 

Q30d,allowable = Allowable 30-day rolling average Waste Gas Flow Rate taken 

from the Consent Decree, in scfd 

VOC30d,vol fraction = 30-day flow weighted rolling average VOC volume fraction in the 

Waste Gas on the day that the 30-day rolling average limit is 

violated. [NOTE: This is the VOC fraction in the Waste Gas, not 

the Vent Gas.] The daily flow weighted average VOC volume 

fraction shall be determined from an average of the hourly average 

 VOC concentration weighted by waste gas flow. The 30-day flow 

 weighted rolling average VOC volume fraction shall be determined 

from daily flow weighted CE and daily flow of waste gas. 

.0026 = 1 lb-mole VOC/385.5 scf 

MW30d,VOC = 30-day flow weighted rolling average Molecular Weight of VOCs 

on the day that the 30-day rolling average limit is violated, in lb/lbmole. The daily flow weighted average molecular weight (MW) 

shall be determined from an average of the hourly average MW 

weighted by waste gas flow. The 30-day flow weighted rolling 

average MW shall be determined from daily flow weighted MW 

and daily flow of waste gas. 

.0005 = 1 ton/2000 lb 

2 of 4 
 

 

 

 

 

Case 4:13-cv-02009 Document 2-2 Filed in TXSD on 07/10/13 Page 58 of 75 

APPENDIX 1.13 

CE30d,as fraction = 30-day rolling average Combustion Efficiency (“CE”) determined 

 from the NHVcz of the Combustion Zone Gas as follows: 

NHVcz (BTU/scf) CEas fraction 

NHVcz < 95 0.0 

95<= NHVcz <300 [0.16*(-95+ NHVcz)]/[1+0.16*(-95+ NHVcz)] 

300<= NHVcz <350 0.98 

350<= NHVcz <425 0.985 

425<= NHVcz <500 0.9875 

500<= NHVcz <600 0.99 

600<= NHVcz 0.995 

Combustion Efficiency shall be determined hourly from the hourly 

average NHVcz using the table above. The daily flow weighted 

average CE shall be determined from an average of the hourly 

average CE values weighted by waste gas flow. The 30-day flow 

weighted rolling average CE shall be determined from daily flow 

weighted CE and daily flow of waste gas. 

B. Violating the 365-day rolling average limit. To calculate the 365-day average 

VOC emissions above the flow limit for the day that the 365-day rolling average limit is 

violated: 

Substitute “365” everywhere “30” appears in Equation 3.a (Eq. 3.b) 

[Appendix continued on next page] 

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Case 4:13-cv-02009 Document 2-2 Filed in TXSD on 07/10/13 Page 59 of 75 

APPENDIX 1.13 

IV. Calculating the Average Emissions of SO2 Above the Flow Limit when Violating the 

30-Day and 365-Day Rolling Average Limit 

A. Violating the 30-day rolling average limit. The following equation shall be 

used to calculate the 30-day average SO2 emissions above the flow limit for the day that the 

30-day rolling average limit is violated: 

EE30d,SO2 = [Q30d,actual – Q30d,allowable] [C30d,H2S/1,000,000] [8.30 x 10-5] (Eq. 4.a) 

Where: 

EE30d,SO2 = 30-day average SO2 emissions above the flow limit on the day that 

the 30-day rolling average limit is violated, in tons per day 

Q30d,actual = Actual 30-day rolling average Waste Gas Flow Rate on the day 

 that the 30-day rolling average limit is violated, in scfd 

Q30d,allowable = Allowable 30-day rolling average Waste Gas Flow Rate taken 

from the Consent Decree, in scfd 

C30d,H2S = 30-day rolling average concentration of H2S in Waste Gas on the 

 day that the that the 30-day rolling average limit is violated, in 

 ppmv 

8.30 x 10-5 = [1 lb-mole H2S/385.5 scf] [64 lb SO2/lb-mole H2S] [Ton/2000 lb] 

B. Violating the 365-day rolling average limit. To calculate the 365-day average 

emissions of SO2 above the flow limit for the day the 365-day rolling average limit is violated: 

Substitute “365” everywhere “30” appears in Equation 4.a (Eq. 4.b) 

[End of Appendix] 

4 of 4 
Case 4:13-cv-02009 Document 2-2 Filed in TXSD on 07/10/13 Page 60 of 75 

UNITED STATES
 

v. 

SHELL OIL COMPANY, ET AL. 

APPENDICES TO CONSENT DECREE 

APPENDIX 1.14 

EQUATIONS AND METHODOLOGY TO 

CALCULATE REFINERY-SPECIFIC 

COMPLEXITY AND INDUSTRY-AVERAGE 

COMPLEXITY USING NELSON COMPLEXITY 

INDEX 
APPENDIX 1.14

DETERMINING REFINERY-SPECIFIC AND INDUSTRY-AVERAGE COMPLEXITY

THROUGH USE OF THE NELSON COMPLEXITY INDEX

DEFINITIONS:

"Applicable EIA Annual Refinery Publication" shall mean the Annual EIA Refinery Publication that was

the most recent one posted on EIA's website prior to a refinery's request for an increase in flaring caps.

"Applicable Form EIA-820" shall mean the Form EIA-820 that forms the source for the requesting

refinery's capacity information that is summarized and compiled in the Applicable Annual EIA Refinery

Publication.

For.example, if a Nefinery Nequests an increase in flaring caps in March of 201 S, the

"Applicable FoNm EIA-820, " is the FoNm EIA-820 that the Refinery submitted prior to

February 1 S, 2014, for its capacities as of January 1, 2014, (and not the Form EIA-820

that the Refinery submitted prior to FebNUary I5, 201 S, for its capacities as of January 1,

2015). This is because the Applicable EIA Annual Refinery Publication is the one

published in June of 2014 (i. e., the last one published prior to March of 201 S).

"Applicable O&GJ Refining Survey" shall mean the survey that is published in December of the year

prior to the year of the Applicable EIA Annual Refinery Publication.

For example, if the Applicable EIA Annual Refinery Publication is the one published in

June of 2014, then the Applicable O&GJRefinery Survey is the one published in Decefnber

of 2013 foN capacities as of January 1, 2014.

"EIA" shall mean the United States Energy Information Agency.

"EIA Annual Publication of the Number and Capacity of Petroleum Refineries" or "EIA Annual Refinery

Publication" shall mean the information posted on EIA's website on approximately June 21 of each year

that compiles and summarizes the data submitted on the Form EIA-820s that each refinery submits prior

to February 15 of that year. As of Apri12013, the most recent Annual EIA Refinery Publication (i.e.,the

one from June of 2012) is found at http://www.eia.gov/dnav/pet/pet~np capl dcu nus a.htm. A

printout of this publication is Attachment 1 to this Appendix 1.14.

"Form EIA-820" shall mean the annual report that each refinery is required to submit to the EIA prior to

February 15 of each year. The "Report Year" of a Form EIA-820 refers to the capacities that exist as of

January 1 of the "Report Year." A copy of a typical Form EIA-820 is Attachment 2 to this Appendix 1.14.

"Oil &Gas Journal Worldwide Refining Survey" or "O&GJ Refining Survey" shall mean the survey that

the Oil &Gas Journal publishes in December of each year that lists refining capacities as of January 1 of

the following year. A copy of the national refining capacities listed in the December 5, 2011 O&GJ

Refining Survey for January 1, 2012 is Attachment 3 to this Appendix 1.14. The relevant United States

capacities are highlighted in yellow on the third page of Attachment 3.

1 of 4 (excluding Attachments)

Case 4:13-cv-02009 Document 2-2 Filed in TXSD on 07/10/13 Page 61 of 75 
APPENDIX 1.14

REFINERY COMPLEXITY. The complexity of the Refinery is to be calculated using the following

formula:

Equation 1

Complexity = ~ NCI= x CAP

n_, CAP~,st

Where:

NCI; = The 2011 Nelson Complexity Index Coefficient shown in Table 1 below for Process

Unit i

The throughput capacity for the Refinery's Process Unit i, in barrels per calendar day,

which shall be determined as follows:

(a) for a Process Unit that is not new or modified and for which the Applicable EIA

Annual Refinery Publication lists total US throughput for that process, the capacity, in

barrels per calendar day, that the Refinery reported for Procession Part 6~1 of the

Applicable Form EIA-820. If the Refinery did not report the capacity of Process i in

"barrels per calendar day," but instead reported it in "barrels per stream day," then

"barrels per stream day" will be converted to "barrels per calendar day" by multiplying

"barrels per stream day" by the following factors: 0.95 for a vacuum distillation unit

CAP; = and 0.9 for all other units; or

(b) for a process unit that is not new or modified, if and only if the Applicable EIA

Annual Refinery Publication does not list total US throughput capacity for that

process unit, then the Refinery's capacity for that process unit, in barrels per calendar

day, listed in the Applicable O&GJ Refining Survey.

(c) for a Process Unit that is new or modified, where the new or modified capacity was

not reported on the Applicable Form EIA-820, the'projected new or modified unit

capacity that is set forth in the air permit applications) for the post-Lodging

modification.

The Refinery's Atmospheric Crude Oil Distillation Capacity, in barrels per calendar

day, which shall be determined as follows:

(a) if the post-Lodging modification does not affect the crude capacity, the

CAPDIST = Atmospheric Crude Oil Distillation Capacity, in barrels per calendar day, that the

Refinery reported under Total Operable capacity on Part 5, Code 401- of the

Applicable Form EIA-820; or

(b) if the post-Lodging modification does affect crude capacity, the projected, new

capacity set forth in the air permit applications) for the post-Lodging modification.

~1 The references to particular "Parts" or "Codes" of Form EIA-820 are to the Parts and Codes as they exist for the

Form EIA-820 that was used for Report Year 2012. See Attachment 2. To that extent that the "Parts" or "Codes"

on Form EIA-820 are changed in the future, the intent of the Parties is that the "Parts" and "Codes" of future forms

that correspond most closely to those found on the Form EIA-820 for Report Year 2012 will be used.

2 of 4 (excluding Attachments)

Case 4:13-cv-02009 Document 2-2 Filed in TXSD on 07/10/13 Page 62 of 75 
APPENDIX 1.14

INDUSTRY AVERAGE COMPLEXITY: The Industry Average Complexity is to be calculated using

the following formula:

Equation 2

Industry_Average_Complexity = ~ NCI! x ICAP

n-1 ICAPD,St

Where:

NCI; = The 2011 Nelson Complexity Index Coefficient shown in Table 1 below for Process

Unit i

Total US throughput capacity, in barrels per calendar day, for Process Unit i which

shall be determined as follows:

(a) from the Applicable EIA Annual Refinery Publication, the total US capacity of

Process Unit i in barrels per calendar day. For the total US capacity of those process

units that the EIA lists only in "barrels per stream day" and not in "barrels per calendar

day," the "barrels per stream day" shall be converted to "barrels per calendar day" by

ICAP; = multiplying "barrels per stream day" by the following factors: 0.95 for a vacuum

distillation unit and 0.9 for all other units.~2

(b) if and only if the Applicable EIA Annual Refinery Publication does not list a total

US throughput capacity for a process unit that the Refinery operates, then the total US

throughput capacity for that process unit listed in the Applicable O&GJ Refining

Survey.

From the Applicable EIA Annual Refinery Publication, the total "Operable" US

ICAPDIST = Atmospheric Crude Oil Distillation Capacity, in barrels per calendar day.3

~2 For example, for catalytic reforming, the total US capacity as of January 1, 2012, is 3,246,874 barrels per

calendar day. See Attachment 1 at page 2 (green highlight). Note that the capacity for catalytic reforming on

page 1 of Attachment 1 should not be used because that is listed in "barrels per stream day," not bpcd. For vacuum

distillation, the total US capacity for 2012 is 8,679,643 barrels per stream day. See id. at page 1 (orange highlight).

This figure would be converted to 8,245,660 barrels per calendar day (8,679,643 x .95).

~3 Total Operable US Atmospheric Crude Oil Distillation Capacity (total ICAPDIST) of a January 1, 2012, is

17,322,178 barrels per calendar day. See Attachment 1 at page 1 (yellow highlight).

3 of 4 (excluding Attachments)

Case 4:13-cv-02009 Document 2-2 Filed in TXSD on 07/10/13 Page 63 of 75 
APPENDIX 1.14

Table 1: 201.1 Nelson Complexity Index Coefficients

Refining Process NCI Coefficients

Distillation Capacity 1.00

Vacuum Distillation 1.30

Thermal Processes 2.75

Coking 7.50

Catalytic Cracking 6.00

Catalytic Reforming 5.00

Catalytic Hydrocracking 8.00

Catalytic Hydrorefining 2.50

Catalytic Hydrotreating 2.50

Alkylation 10.00

Polymerization 10.00

Aromatics 20.00

Isomerization 3.00

Lubes 60.00

Asphalt 1.50

Hydrogen (MCFD) 1.00

Oxygenates 10.00

Sulfur Extraction 240.00

of 4 (excluding Attachments)

Case 4:13-cv-02009 Document 2-2 Filed in TXSD on 07/10/13 Page 64 of 75 
APPENDIX 1.14

ATTACHMENT 1

Case 4:13-cv-02009 Document 2-2 Filed in TXSD on 07/10/13 Page 65 of 75 
U.S. Number and Capacity of Petroleum Refineries

eiaU S. Energy Information

Administration

PETROLEUM &OTHER LIQUIDS

Page 1 of 2

OVERVIEW DATA ANALYSIS &PROJECTIONS GLOSSARY> FAQS>

Number and Capacity of Petroleum Refineries

Area: U.S. ~ Perfod: Annual (as of January 1)

Show ~a[a By: GraOh

~ Data Sena (~ Area ~ Gear 2007 2008 2009 2010 2011

View

2012 History

!~~~tf.~F»t11b1~ R}flSle[iea

Total Number of Operable

R~neries ~_! 149 150 150 148 148 144 ~ -2ot2

Operating ... 145 148 141 137 137 134 1982-2012

Idle 4 4 9 11 11 10 ~982"20~2

~.,. „~jC

Operable (Barrels per Calendar

Day) ....: 17,443,492 17,593,847 17,671,550 17,583,790 17,736,370 17,322,178 1982.2012

Operating 16,997.792 17,225,797 17,313,550 16,850,194 16,937,024 16,744,291 te82-2012

Idle i.: 445,700 368,050 358,000 733,596 799,346 577,887 1982-2012

Operable (Barrels per Stream Day) ~

.. ~.. _~__

~g,gz5,322 18,558,022 18,661,308 18,581,089 18,953,189 18,560,350 1982-2012

Operating i 17.926.522 18.174,072 18.300.358 17,808,082 18.109,882 17,945,443 1982-2012

~~e ~ 496,800 383,950 360,950 773,007 843,307 614,907 198 - 1

i a

~ Vacuum Distlllaiion ~ 8,251,451 .. 8,420,501 8,542,287 8,542,643 8,650,243 ~675i;813; 7,582"2012

Thermal Cracking 2,564,080 2,606,260 2,639,090 2,631,676 2,672,376 2,763,356 1 ~2

Total Coking 2,537,480 2,579,660 2,612,490 2,605,076 2,645,776 2,736,756 ~987.20i2

Delayed Coking 2,331,580 2,374,280 2,454,590 2,500,676 2,486,876 2,577,856 ~ s9 7-202

Fluid Coking 205,900 205,400 157,900 104,400 158,900 158,900 1 89 7.2072

Visbreaking 16,000 16,000 16,000 16,000 16,000 16,000 X987-2012

Other (Including Gas Oil) 10,600 10,800 10,600 10,600 10,600 10,600 1987-2012

Catalytic Cracking -Fresh Feed 6,216,957 6,265,697 6.291,871 6,140,121 6,219,721 6,032,512 1982-212

Catalytic Cracking - Recycle Feed

~

82,040 78,740 78,740 91,840 95,640 84,880 19 2- 1

Catalytic Hydro-Cracking 1,790,682 1,770,325 7,743,300 1,819,700 1,855,600 1,879,600 1982-20t2

Distillate 602,800 558,900 593,100 585.200 540,100 596,500 02 04-2012

Gas Oil gg7,482 1,004,425 1,010,200 1,079,500 1,170,500 1,161,100 2oD4.2o72

Residual 200,400 209,000 140,000 145,000 145,000 122,000 2D04-202

CatalyficReforming 3,907,510 3,891,938 3,829,338 3.700,483 3,720,613 3,641,813 1982-202

Low Pressure ~ 2,354,950 2.402,350 2,397,750 2,322,700 2,390,950 2,347,650 1987-202

High Pressure '~ 1,552,560 1,489,588 1,431,588 1,377,763 1,329,863 1,293,963 1987.2012

Catalytic

Hydrotrealing/DesulTurization 15,447,136 15,807,476 16,130,823 16,023,206 16,682,897 18,565,262 1982-2012

NaphthalReformerFeed 4,453,890 4.348,590 4,334,297 3,281,046 4,441,323 4,360,593 19872012

Gasoline 2,221,568 2,420,968 2,415,282 2,394,882 2,578,782 2,519,082 2004"2012

Heavy Gas Oil ~ 2,578,840 2,672.440 2.735,538 2.796,798 2.809.298 2.877,138 X987.2012

Distillate Fuel Oil 5,212,387 5,462,649 5,622,252 5,676,032 6.113,846 6,063,001 j~97.20~2

Kerosene/Jet Fuel 1,009,450 1,137,010 1,160,110 1,339,150 1,484,850 1,489,750 X0042012

Diesel Fuel 3,332,671 3,468,471 3,551,211 3,647,211 3,917,611 3,981,411 20082012

OEher Distillate I 870,266 857,166 910,931 689,671 771,385 591,840 ZOW.2012

Residual Fuel Oil/Other 980,451 902,831 1,023,454 874,448 739,648 745,446 1987.2012

Residual Fuel Oil 331,420 251,200 316,400 246,200 241,000 246,000 20 - 1

Other 649,031 651,631 707,054 628,248 498,648 499,448 2004"202

http://www.eia.gov/dnav/pet/pet~np_capl_dcu_nus_a.htm 4/25/2013

Case 4:13-cv-02009 Document 2-2 Filed in TXSD on 07/10/13 Page 66 of 75 
U.S. Number and Capacity of Petroleum Refineries

Fuels Solvent Deasphalting I ~`

~ _. ~ e a ~ ~

Catalytic Reforming (' °,

Total Colang

Catalytic Cracking -Fresh Feed i ',

Catalytic Hydro-Cradclnp i i_

379,290 378,3501 380,950 383,250 382.750' 374.650] - 12

3,378,841 3,346,457 3,246,874;20~0.20~2

2,359.3181 2,390.223, 2,428,9811 2.387,898 2.396.787 2,499,293~1s87.2612

5,830,486 5,853,656 5,847,130 5,675,830 5,794,214 5,611,191' 1887.2012

1,620,705 1,602,431 1,592,973 '1,663,115 1,687.745 1,706,540 1987.2012

-= No Data RepoAed; --=Not Applicable; NA =Not Available; W = Nhthheld to avoid disclosure of ind~vitlual company data.

NoMS: Idle rcfinaries represent refineries where distillation units were completely idle but not permanently shutdovm as of January 1 of the year. See

Dafinifions, Sources, and Notea Iink above for more information on this table.

Release Date: 8/22/2012 Ne# RBlease Date: 6/2120 3

http://www.eia.gov/dnav/pet/pet~np_capl_dcu nus_a.htm

Page 2 of 2

4/25/2013

Case 4:13-cv-02009 Document 2-2 Filed in TXSD on 07/10/13 Page 67 of 75 
APPENDIX 1.14

ATTACHMENT 2

Case 4:13-cv-02009 Document 2-2 Filed in TXSD on 07/10/13 Page 68 of 75 
~_A.

U.S. Energy Information e 1 a Administrarion

OMB No. 1905-0165

Expiration Date: 1/31/2013

Version No.:2010.02

FORM EIA-820

ANNUAL REFINERY REPORT

REPORT YEAR 2012 -- report is mandatory under the Federal Energy Administration Act of 1974 (Public Law 93-275). Fa+lure to comply may result in criminal fines, civil penalties and

sanctions as provided by law. For further information concerning sanctions and data protections see the provision on sanctions and the provision concerning the

dentiality of information in the instructions. Title 18 USC 1001 makes it a criminal offense for any person knowingly and willingly makes to any Agency or

irtment of Ute United States any false, fictitious, or fraudulent statements as to any matter within its jurisdiction.

;T 1. RESPONDENT IDENTIFICATION DATA PART 2. 3UBMISSIONlRESUBMlSSION INFORMATION

ID NUMBER: r 133957010

If any Respondent Identification Data has changed since the last report,

enter an "X" in the box:

Company Name: Shell Oil Co.

Doing Business As:

Name: DEER PAi2K REFG LTD PTNRSHP

Final Control Number (TCN):

iysical Address (e.g., Street Address, Building Number, Floor, Suite):

HWY 225

City DEER PARK State: TX Z~p~ 77536 - 0100

Mailing Address of Contact (e.g., PO Box, RR): If the physical and

mailing addresses are the same, only complete the physical address.

P.O. BOX 100

City DEER PARK State: TX Z~P~ 77535 - 0100

Contact Name:

Phone No.: - 

~ .._. Ext: ~

Fax No.: ~ __

Email address:

If this is a resubmission, enter an "X" in the box:

A completed form must be received by February 15th of the

designated report year.

Forms may be submitted using one of the following methods:

Email: 00 U~YS~eia.gov

Fax: (202}586-1076

Secure File Transfer:

httos:/lsiq non. eia. doe.govlu ploa dJn oticeooa.is a

Questions? Cail: 202-386-6281

~S: Explain any unusual or substantially different aspects of your current year's operations that affect the data reported. For example, note new

ig units, major modifications or retirement of processing unib, sale of refinery, etc. (To separate one comment from another, press ALT+ENTER)

Case 4:13-cv-02009 Document 2-2 Filed in TXSD on 07/10/13 Page 69 of 75 
.:..,,:.:, ,; _; :..~ :,:,: OMB No. 1905-0165

~' l U.S. Energy Information Expiration Date: 1/31/2013 ela Administration Version No.:2010.02

Fo~nn Eia-sza

ANNUAL REFINERY REPORT

REPORT YEAR 2012

EIA ID NUMBER: 1339570101 RESUBMISSION:

PART 3. FUEL. ELECTRICI'T'Y. AND STEAM PURC1iASED &CONSUMED AT THE REFINERY DURING 2Q11

PART 5. ATMOSPHERIC CRUDE OIL DISTILLATION CAPACITY AS O~ JANUARY 1

Atmos heric Crude OiP Distillation Capacity Code Barrel per Calendar Day2 Barrels er Stream Da

2012: O eratin 399 327000 327000

Idle 400 0 0

Total O erable 401 327000 327000

2013: O erable 50~ 327000

Z Barrels per Calendar Day Operating, Idle and Total Operable Capacity (Codes 399, 400 and 401) must match the comparable capacity numbers reported on the Form

EIA-810, "Monthly Refinery Report," filed for January 2012.

Case 4:13-cv-02009 Document 2-2 Filed in TXSD on 07/10/13 Page 70 of 75 
,,, ; , , ,, ,,,,, ,~ ~..:,, .. OMB No. 1905-016

U.S. Energy Information Expiration Date: 1/31/201

~1~ Administration Version No.:2010.02

FORM EIA-820

ANNUAL REFINERY REPORT

REPORT YEAR 2012

EIA ID NUMBER: 1339570101 RESUBMISSION:

PART 6. DOWNSTREAM CHARGE CAPACITY AS OF JANUARY 1

Downstream Charge Capacity Code

2012

Barrels per

Calendar Day

2012

Barrels per

Stream Day

2013

Barrels per

Stream Day

Vacuum Distillation 402 180000 180000

Thermal Cracking:

Visbreaking 403 ~ 0

Fluid Coking (incl. Flexicokin) 404 0 0 0

Dela ed Coking 405 83600 89300 89000

Other incl. Gas Oil) 406 ~ 0

CatalyticCrackin .~ , -~~ ~~ ° 'r

Fresh Feed 407 63600 70000 70000

Rec cied 408 5000 5000

Catal tic Hydrocracking: .,'~ ~~~~ ~ '`

Distillate 439 0 0 0

Gas Oil 440 55000 60000 60000

Residual 441 0 0 p

Desulfurization (including Catalytic Hydrotreating): x ~ ' >:,~ ~ ~° ~;s

Na htha/Reformer Feed 426 75000 75000

Gasoline 420 42000 42000

Kerosene and Jet 421 40000 40000

Diesel Fuel 422 ~ 0

Other Distillate 423 45000 45000

Residual 424 49500 49500

Heavy Gas Oil 413 80000 86000

Other 425 43fl00 43000

Catal tic Reformin

Low Pressure 430 42900 45000 45000

High Pressure 431 22700 24500 24500

Fuels Solvent Deas haltin 432

PART 7. PRODUCTION CAPACITY AS OF JANUARY 1 Barrels er Stream Da , Exce t Where Noted

Production Ca aci Code

2012 2013

Aik lates 415 18500 18500

Aromatics 437 0 0

As halt and Road Oil 931 o ~

Isobutane C4 644 o ~

Iso entane C5 , Isohexane C6 438 ~ 0

Isooctane C8) 635 ~ 0

Lubricants 854 0 0

Petroleum Coke - Marketable 027 38701 38701

H dro en million cubic ft. er da) 091 ~ ~8 100

Sulfur short tons er da J 435 1085 1085

Case 4:13-cv-02009 Document 2-2 Filed in TXSD on 07/10/13 Page 71 of 75 
APPENDIX 1.14

ATTACHMENT 3

Case 4:13-cv-02009 Document 2-2 Filed in TXSD on 07/10/13 Page 72 of 75 
2011 

Leena Koottungal

Worldwide Refinin g Surve Y

Survey Editor/r1►ews Writer

A!I figures in barrels per calendar day {blcd} 

LEGEND

Numbers idenfrfy processes in ta61e

Coking Catalytic reforming Catalytic hydrotreating Ablation Isomerization 

1. Fluid_ coking 1. Semiregenerative 1. Pretreatment of cat reformer feeds 1, ulfuric acid 1. C4 feed 

2. Delayed coking 2. Cyclic ~ 2. Ofher naphtha desulfurization ~ 2. Hydrofluoric acid 2. C5 feed 

3. Other 3. Continuous regen. 3. Naphtha aromatics saturation 3. C5 and Cg feed 

4. Other 4. Kerosine/jet desuffurization Polymerization/Qimerization 

Thermal process 5. Diesel desulfurization i. Polymerization Oxygenates 

1. Thermal cracking Catalytic hydrocrackin` 6. Distillate aromatics saturation 2. Dimerization 1. MTBE 

2. Visbreaking 1. Distillate upgrading 7. Other distillates 2. ETBE 

2. Residual upgrading 8. Pretreatment of cat cracker feeds Aromatics 3. TAME 

Catalypc cracking 3. Lube oil manufacturing 9. Other heavy gas oil hydrotreating 1. BTX 4. Other 

1, Fluid 4. Other 10. Resid hydrotreating 2. Hydrodeal.kylation 

2. Other c. Conventional (high pressure) 11. Lube oil polishing 3. Cyclohexane

hydrocracking: (>lOd barg or 12. Post hydrotreating of FCC naphtha 4. Cumene

1,450 psig) 13. Other

m. Mild to moderate hydrocracking (<I00 harg or 1,450 psig)

NOTES

A New I Previousty listed as SK Corp. Q Plans to sell

B Previo~ GsleA as CUevron Cmp. J Previousty listed as Hyundai Oil Relipery Ca R Previously listed as Sunoco Inc.

C Prerioast~ k~e9 asSheN U.K. Ltd. K Previousty listed as Nolly Corp. S Plans to convert to a storage (aciiry

D Prevroaary listed as A6E Refleia~ & ManuFaduring L New to survey T Far sale

E Prtviousy lists as Nmrplry 0~ USA Ine. M Shut down U Previously listed as Valera Energy Corp.

F Nay canroR iMo a kei inpon ternioal N Preuiousty listed as Frontier Oil Cap. U Ptevinusiy listed as Maraihan Petroleum Co

6 Idled 0 Previously lists as Frontier Refining Ine. W Previously listed as Shell oeutsch4and Oil G

H keriasly (sled x Dil Refiietks ltd. P Previously listed as CanocoPhillips

Capacitq idinition~ Hydro;en: Catalytic reforming:

Capacity expressed in barrels per calendar day (b/ed) is the maximum 1. Semiregenerative reforming i

number of barrels of input that can be processed during a 24-hour period, Hydrogen volumes presented here represent either generation or reforming unit at specified in

after making albwances for the fallowing (a) Types and grades of inputs upgrading to 90+% purity. for in situ cat2lyst regenerati

to be processed, (b} Types and grades of products to be manufactured, (c) 2. Cyclic regeneration reformin

Environmental constraints associated with refinery operations, (d) Scheduted tinual regeneration of catalys

downtime such as mechanical problems, repairs, and slowdown. Capacity that can be isolated from and 

expressed in barrels per stream day (b/sd) is the amount a unit can process This fs accomplished withou

when running at full capacity under optimal feedstock and product slate 3. Continuous regeneration re#o

conditions. An asterisk (*) beside a refinery Location indicates that the number addition of this regenerated 

has been converted from blsd to b/cd using the conversion factor 0.95 for 4. "Other" includes nonregener

O crude and vacuum distillation units and 0.9 for all downstream cracking and fresh cata{yst) and moving-b

conversion units.

m

o REFINERY REMQVALS c

w Name Location Cnu~r Crude Wcd Reason

~ Western R~ioing Yorldown, Virginia US 70,000 Shut down

c~~u Surrom k~c. WaNille, NJ US 150,000 Shutdown

Abn USA Bakersfield, Calif. US 70,000 Integrated wAh Paramount refinery

cn Ndly Cap. Tufsa, Okla. US 85,OIX1 Integrated w~h other Tulsa refinery

Total SA Dunkirk Fraixe 137,028 Shutdown

Pak-Arab Reficery Co. Mahmood Kot, P~jab Pakistan 1(p,000 Shutdown

~.. PeUoplus Haldmgs AG Cressier Sxitrerlarrd 60,000 Shut dorm

Case 4:13-cv-02009 Document 2-2 Filed in TXSD on 07/10/13 Page 73 of 75 
0 Worldwide Refineries-Capacities as of Jan. 1, 2012

o 

~yNo. CuuMry of refineries Rude Yacuum distillation Eotiaa Thermal operations Charge capacity, Mcd Catalytic Catalytic cracFing reforming Catalytic hydroeracNing ----Catalytic hydrotreating Alkylatinn PoIJIYim. Aromatics Isomerization Production capac'~ry, Nc

lobes Oxygena

c

~ Albania ............. 2 26,300 10,500 12,000 - - 3,500 - 17,400 600 - 700 - 

v Algeria ............. 4 450,000 IQ,894 - - - 88,900 " - 81,950 - - - - - - 

~ M~la ............. 1 39,000 2,500 - - - 1,900 - 6,600 - - - - - - 

~ Argentina ........... 10 630,575 248,365 91,233 38,420 141,180 5fi,630 I7,~00 175,500 4,300 520 - 12,700 7,290 2,60

~ Aruba .............. 1 235,000 166,250 68,40Q 30,600 - - - 214,200 - - - - - - 

~ Australia.,.......... 7 760,148 192,865 - - 235,043 172,053 18,407 543,531 24,734 10,609 1,000 39,606 - - 

~ Austria ............. 1 208,600 65,W0 - 16,875 26,256 32,725 - 134,400 - - - 14,4Q0 - t,60

p Azerbaijan..:.......: 2 398,478 1'37,200 38,529 - 57,750 24,466 - b7,492 930 - - - 16,206 - 

~ Bahrain .,.,,.,,.... 1 253,650 198,170 - 21,600 35,100 13,500 54,000 76,5Q0 - 3,330 - - - - 

Bar~ladesh.......... 1 33,000 4,000 - 10,000 - 1,8W 1,200 2,000 - - - - - - 

Belann ............. 2 493,323 105,806 - 60,000 44,000 92,000 30,000 262,100 - - 2,785 4,500 3,760 - 

Belgium............ 4 739,821 250,630 - 30,016 133,553 105,589 - 687,755 17,630 - - 0 - 3,76

Bolivia ............. 2 41,200 2,200 - - - 12,100 - 6,899 - - - - - - 

Bruil .............. 13 1,917,333 810,140 115,319 9,800 505,287 24,386 - 284,446 6,290 - - - 20,009 6,46

Brurrei ............. 1 8,600 - - - - 5,700 - - - - - - - - 

8ulgaria,........... 1 115,240 49,900 - 2Q,600 23,300 4,060 - 64,200 2,600 - 2,000 - - 790 

Cameroon........... 1 37,000 - - - - 6,500 - 16,140 - - - - - - 

Canada ............. 17 1,91$,455 645,056 59,100 121,430 482,468 354,930 210,374 1,383,536 70,403 19,240 62,689 62,490 3,000 - 

Chile .............. 3 226,800 85,050 13,860 13,860 50,540 26,460 50,400 - 910 - - 8,51Q - 1,58

China .............. 54 6,856,000 240,000 156,0 - 588,OW 178,000 185,(H10 541,000 15,500 - 21,000 - 18,000 9~ 

China,Tanran........ 4 1,310,00 2A8,506 51,~o - 217,900 115,IX10 25,0[10 672,500 14,200 - 14,000 25,000 15,300 11,26

Cobmhia ........... 5 240,850 141,006 - 52,000 90,OW - - 19,800 2,100 2,100 2,200 - 1,400 - 

Cor~o (BrazuvilW .... 1 21,000 8,066 - - - 2,IX10 2,000 3,500 - - - - - - 

Costa Rica ...... , ... 1 24,000 600 - 6,500 - 1,200 - 2,000 - - - - - - 

Craatia ............. 3 250,317 87,040 5,000 23,526 51,002 49,368 12,264 68,256 - - 9,438 5,431 470 - 

Cuba ......... . . . . . 4 301,404 75,700 - - 14,7D0 20,000 - 55,850 - - - - - - 

Czech Republic....... 3 183,000 78,870 - 17,000 - 27,470 34,430 103,180 - - fi60 7,210 2,180 2,16

Denmark...........: 2 174,400 22,000 - 64,55Q - 21,990 - 42,760 - - - 6,400 - - 

Daninican Repudic ... 2 50,000 - - - - 8,200 - 20,913 - - - - - - 

Ecuador............ 3 176,000 45,300 - 31,500 18,00 12,800 - 24,500 - - - - - - 

Egypt .............. 9 726,250 95,2f10 34,276 - - 62,240 33,506 207,802 9,000 - 1,584 14,700 4,441 - 

EiSaivada......,... 1 22,000 4,OW - - - 3,000 - 15,500 - - - - - - 

Eritrea ............. 1 1A,564 2,219 - - - 1.465 - 2,742 - - - - - - 

Finiand ............. 2 260,575 14b,085 - 34,420 56,690 50,060 90,110 298,325 7,750 640 - - 5,280 5,73

France ............. 12 1,718,803 715,200 - 146,872 347,052 256,669 11,845 1,233,04$ 26,7Q2 2,968 2,887 48,492 36,390 4,71

Gabon ............. 1 24,(100 - - 9,220 - 1,400 - 9,430

Germany............ 15 2,417,162 1,496,231 105,809 247,445 349,171 404,822 2Q3,467 2,011,782 30,885 8,301 71,944 44,226 14,220 13,17

Ghana ............. 1 45,000 - - - 14,000 65,000 - - - - - - - - 

Greece ............. 4 423,000 152,000 - 49,000 75,550 49,200 43,900 361,635 2,400 1,720 9,100 23,650 3,500 3,94

Hungary............ 1 1fi1,000 77,50 16,900 14,00 24,60 29,66 - 120,700 3,300 - 12,000 3,50 fi,100 1,20

India .............. 21 4,042,761 811,986 169,625 43,180 531,305 51,673 165,6fl~ 250,742 85,000 - 9,742 - 6,240 1,39

Inda~sia ........... S 1,011,825 265,980 32,580 58,9fi0 101,450 92,970 99,720 23,430 16,200 - - - - - 

Iran ............... 9 1,451,000 559,400 - 290,800 35,000 164,7W 136,500 183,160 - - - - 19,60Q - 

Iraq ............... 9 637,500 145,000 - - - 88,000 74,241 292,000 - - - 2.500 9,420 - 

Ireland ....... . ..... 1 71,006 - - - - 11,E - 44,600 - - - 7,600 - - 

lsrael .............. 2 220,000 (18,000 - 66,000 44,5 26,5 - 96,000 - 2,2 0 - - - 75Ita{y ............... 17 2,337,229 &14,237 45,OIX} 448,204 321,500 287,069 30.3,210 1,250,753 40,33Q 1,500 13,400 112,260 24,000 11,72

lvay Cwst .......... 1 63,990 23,990 - - - 12,330 14,480 27,310 - - - - - - 

Jamaica ............ 1 36,OOD 1,800 - - - 3,700 - 23,800 - - - - - - 

Japan .............. 3D 4,729,890 1,764,195 I23,40(f 20,000 98fi,980 829,225 181,690 5,416,160 74,690 5,760 207,467 31,350 38,013 2,97

Jordan ............. 1 90,400 21,500 - - 4,000 10,9 5,220 17,300 - - - - - - 

Kankhstan.......... 3 345,093 121,037 24,497 52,071 38,356 51,586 - ll7,890 - - - - - - 

Kenya .............. 1 90,000 1,700 - - - 8,260 - 36,000 - - - - - - 

Kuttait ............. 3 936,000 327,750 72,000 - 36,000 46,624 115,650 588,780 5,61fi - - - - 6,56

Kyrgyntan .......... 1 10,000 - - - - 

Li6~ia ............. 1 15,000 1,000 - - - 2,000 - 3,300 - - - - - - 

Libya .............. 5 378,000 3,775 - - - 20,250 - A3,330 - - - - 635 - 

Lithuania........... ~ 1 190,000 89,300 - 28,800 43,200 45,A00 - 153,400 -- 7,200 - I8,900 - 2,7IX

Macedonia .......... 1 50,000 - - - - 10,860 - 22.050 - - - 4,390 - - 

Malaysia........... , 7 538,582 94,335 24,040 - 42,700 75,070 36,000 216,800 - - - 14,8U~ - - 

Case 4:13-cv-02009 Document 2-2 Filed in TXSD on 07/10/13 Page 74 of 75 
0

y

0

a

O

n

O

~~..

Worldwide Refineries--Capacities as of Jan. 1, 2012

~ pp~~ry, h~~d Prodectian capacity

No. of Yacwin Tlcermal Catalytic Catatydc Cata{ylic Catalytic 

Country rofineria Gede disGllaliai CoYin~ oQerations cracking reloming hytlroeracking hydmtreating Alkyla6an PoIJDim. AramaGcs IsomerizMion Luhes Orygena

Martinique .......... 1 17,329 - - - - ?,gSZ - 14,269 -

Mexico . . ........... 6 1,540,000 754,W0 191,000 - 380,5U0 279,300 - 926,054 128,456

Morocco............ 2 154,901 24,921 - - 5,040 24,359 - 35,534 -

Myanmar ........... 3 57,600 4,000 5,200 - - - - - -

Netherlaads ......... 6 1,196,571 711,095 41,500 91,4Q4 101,983 148,616 198,071 1,016,234 15,450Netherlands Mtitles .. , 1 320,000 195,000 - 80,000 50,Ood 20,000 - 119,5IXt 4,W0

New Zealand......... 1 107,OOq 38,270 - - - 25,849 30,000. 104,490 -

Nicardgua... , . ,', .... 1 20,000 1,500 - - = 3,000 - 14,506 -

Nigeria ............. 4 445,000 124,490 - - 82,740 70,070 - 109,231 9,870

North Kaea ......... 2 71,000 - - - - 7,300 - 7,400 -

Nanvay ............. 2 319,W0 - 24,78D 32,000 49,000 34,900 - 126,000 -

Oman .............. 1 85,000 - - - - 16,000 - 21,000 -

Pakistan............ 6 186,306 19,815 - - - 11,650 - 54,870 -

Papua New Guinea .... 1 32,500 - - - - - - - -

Paraguay............ 1 7,500 - - - - - - - -

Peru ............... 6 198,950 94,00 - 25,700 33,500 2,100 - 2,8~ -

Philippines.......... 3 273,000 61,000 - 33,E 19,000 51,000 - 184,990 -

Poland ............. 4 492,950 265,123 - - 32,485 67,514 145,9 259,507 3,372

Portugal..........., 2 304,172 87,785 - 36,540 40,500 50,182 9,180 201,537 5,400

Puerto Rico.......... 1 73,000 34,000 - - - 21,000 20,000 21,OW -

Qatar .............. 2 338,700 - - - 60,00 29,400 20,D00 39,350

Ranania............ 10 531,277 273,225 68,240 37,517 1D9,478 61,763 1,534 237,625 2,300

Russia ............. 40 5,430,9118 2,028,570 84,999 382,593 330,817 745,735 57,056 2,17 ,966 10,006

Saudi Arahia......... 7 2,112,000 445,950 - 138,2 1Q3,600 193,160 133,824 493,460 31,500

Senegal ...... , .. , .. 1 25,03Q 7,160 - - - 1,540 - 1,930 -

Serbia & Monter~o... 2 214,826 5D,583 - 20,34Q 18,950 18,822 - 50,910 3,070

Sierraleane......... 1 t0~IN10 - - - - - - - -Singapore........... 3 1,357,000 346,000 - 203,7T6 80,000 146,A70 129,360 706,50Q 9,000

Slovakia , ... , ....... 1 115,000 55,000 - - ., 18,000 21,000 42,000 87,800 4,500

Slovenia............ 1 13,500 - - - - - - - -

Sarth Afica . , ....... 4 484,547 201,375 26,800 60,006 108,644 77,142 11,774 227,712 9,395South Korea ......... 6 2,759,500 515,650 19,00 - 314,000 342,000 326,500 1,450,380 48,70Q

Spain .............. 9 1,271,500 414,245 61,100 149,200 191,300 196,750 131,500 ffi5,380 16,916

Sri Lanka ........... 1 50,000 24,000 - 12,500 - 5,300 - 19,295 -

Sudan .. . ......... . 3 121,700 - - - - 1,900 - 8,100 -

Suriname ........... 1 7,0(10 7,000 - 2,800 - - - - -

Sweden ............ 5 437,W0 135,600 - 66,8 29,700 70,660 48,60 268,540 -

Switrerlantl.......... 1 72,000 - - - 20,400 12,000 - 33,200 -

Syria .............. 2 239,865 63,135 18,2 22,689 - 31,242 26,410 80,886 -

Tanzania............ 1 14,900 - - 2,5IX} - 2,5IX1 - 4,400 -Thailand............ 4 584,250 202,50P - 16,9$3 91,990 97,770 43,073 428,630 -

Trinidad & Tob~o ..... 1 168,000 119206 - Z4,000 24,000 18,000 45,000 41,004 1,200

Tunisia ............. 1 34~OW - - - - 3300 - - -

Turkey ............. 6 714,275 201,767 - 23,590 28,935 65,662 53,820 265,005 -

Turkmenist~ ........ 2 236,970 91,645 28,568 - 15,151 52,540 - 63,50D 1,028

Ukraine ............ 6 879,759 336,297 22,149 17,291 70,100 144,711 7,200 315,013 -United Arah Emirates... 5 773,250 42,81Q - - 34,350 25,875 31,050 158,627 1,140

United Ki~dan ...... 10 1,767,168 866,314 64,6W 106,958 444,723 339,771 36,000 1,271,541 92,202

United States........ 125 17,187,X4 7,909,865 2,543,298 34,020 5,649,659 3,492,288 1,726,030 14,067,515 1,142,127

Uruguay ............ 1 50,QI10 25,000. - 7,OIX1 12.OIX3 12,000 - 23,000 -

Uz6~Cisfan .......... 3 224271 45,671 17,667 9,585 - 23,487 - 30,804 -

Venezuela........... 5 1,282,1OQ 585,780 144,9 - 231,844 44,500 - 389,700 65,8fl0

dietnam ............ 1 140,000 - - - - - - - -

Virgin Islands . , ...... 1 500,00 205,000 55,000 37,000 140,000 105,000 - 435,000 18,O~Q

Yemen ............. 2 140,006 10,500 - - - 14,500 - - -

Zambia ............. 1 23,750 2,280 - - - 5,320 - 8.550 -

iot~l ................ 655 86,055,552 29,062,130 4,681,023 3,8U1,129 14,693,328 11,468,147 5,488,694 45,730,072 2,x,102

- 17,000 - 16,&00 15,49- - - 2,460 - - - - 50Q - 

68,968 8,730 11,600 2,71

2,000 - - 12,000 - 

- . - - - . - 

2,274 291 3,610 3,878 - 

- 1,OIX3 - - 1,0

11,000 - 3,840 - - 

- 1,400 - 3,800 - 

- - - - - - - 1D,00~ 3,700 - - 16,262 23,144 17,796 2,5- 17,276 - - - 

- - - - - - - 25,~D0 - - - 7;801 3,846 10,366 1,3

1,729 54,337 21,869 82,842 7,1

- 6,500 33,0(10 - 3,7

- 200 - 300 

- 48,IX10 - 45,5110 1,4- 9,250 6,000 2,OW 1,5

4,940 6,900 12,223 8,000 

- 140,300 - 66,640 10,5- 25,800 36,000 9,fi00 9,6

- - 

3,420 - 2$,530 - 

3,800 - 6,400 - 

- - 11,493 - 

- 9,500 19,546 - 

1,580 - - - 1,0

- - 14,055 5,870 

1,223 - - 2,000 

- 3,464 - 500 1

1,9IX1 - - - 

13,596 14,590 120,423 23,899 3,9

74,816 464,fi39 678,777 193,100 32,2

- - 6,000 - 

- - - 9,341 

- 2,000 20,700 12,020 12,8

7,006 18,OIX1 17,000 - 

- - - 

- - - - 

195,320 1,311,975 1;x,901 802,516 193,0

Case 4:13-cv-02009 Document 2-2 Filed in TXSD on 07/10/13 Page 75 of 75 
Case 4:13-cv-02009 Document 2-3 Filed in TXSD on 07/10/13 Page 1 of 54 

UNITED STATES
 

v. 

SHELL OIL COMPANY, ET AL. 

APPENDICES TO CONSENT DECREE 

APPENDIX 2.1 

COVERED FLARES AND APPLICABILITY DATES 

FOR CERTAIN CONSENT DECREE 

REQUIREMENTS 
                 

             

         

   

   

   

          

      

   

    

                       

                 

                       

                       

                 

                       

                       

         

   

           

         

   

           

         

   

                             

       

     

                       

                 

Case 4:13-cv-02009 Document 2-3 Filed in TXSD on 07/10/13 Page 2 of 54 

APPENDIX 2.1 ‐‐ Covered Flares and Applicability Dates for Certain Consent Decree Requirements

FLARE

FLARE DATA

AND

MONITORING SYSTEMS

AND

PROTOCOL

REPORT

INSTALLATION

AND

OPERATION

OF

MONITORING SYSTEMS

AND

EXIT VELOCITY

REQUIREMENTS

INITIAL

WASTE GAS

MINIMIZATION PLAN

FIRST

UPDATED

WASTE GAS

MINIMIZATION PLAN

GENERAL

EMISSION

STANDARDS

FOR

COVERED FLARES

WORK PRACTICE

STANDARDS

FOR

COVERED FLARES

SPECIFIC

EMISSION

STANDARDS

FOR

COVERED FLARES

\

A B C D E F G H

‐‐ REFERENCED PARAGRAPHS ‐‐

12.s 16 17, 51 30 31 50 53 55, 56.b‐59

East Property DOE + 365 days 12/31/2013 DOE + 365 days DOE + 730 days DOE DOE DOE + 365 days

Coker DOE + 365 days 12/31/2013 DOE + 365 days DOE + 730 days DOE DOE 6/30/2014

Girbotol DOE + 365 days 12/31/2013 DOE + 365 days DOE + 730 days DOE DOE DOE + 365 days

North Property DOE + 365 days 12/31/2013 DOE + 365 days DOE + 730 days DOE DOE DOE + 365 days

West Property DOE + 365 days 12/31/2013 DOE + 365 days DOE + 730 days DOE DOE 6/30/2014

Olefins Ground DOE + 365 days 12/31/2013 DOE + 365 days DOE + 730 days DOE DOE DOE + 365 days

Olefins II DOE + 365 days 12/31/2013 DOE + 365 days DOE + 730 days DOE

PARA. 53.a.i

06/30/2016

DOE + 365 days

PARA. 53.a.ii

DOE

Olefins III DOE + 365 days 12/31/2013 DOE + 365 days DOE + 730 days DOE

PARA. 53.a.i

06/30/2018

DOE + 365 days

PARA. 53.a.ii

DOE

HIPA DOE + 365 days 12/31/2013 DOE + 365 days DOE + 730 days DOE DOE DOE + 365 days

South Property

(Temporary‐Use)

Prior to receipt of Vent

Gas after DOE

Upon receipt of

Vent Gas

after DOE

N/A N/A DOE

Upon receipt of

Vent Gas

after DOE

Upon receipt of

Vent Gas

after DOE

CCU

(Temporary‐Use)

Prior to receipt of Vent

Gas after DOE

Upon receipt of

Vent Gas

after DOE

N/A N/A DOE

Upon receipt of

Vent Gas

after DOE

Upon receipt of

Vent Gas

after DOE

A&S

(Temporary‐Use)

Prior to receipt of Vent

Gas after 6/30/2013

Upon receipt of Vent Gas

after 6/30/2013 N/A N/A DOE Upon receipt of Vent Gas

after 6/30/2013

Upon receipt of Vent Gas

after 6/30/2013

Legend:

DOE = Date of Entry
Case 4:13-cv-02009 Document 2-3 Filed in TXSD on 07/10/13 Page 3 of 54 

UNITED STATES
 

v. 

SHELL OIL COMPANY, ET AL. 

APPENDICES TO CONSENT DECREE 

APPENDIX 2.2 

INTENTIONALLY LEFT BLANK 
Case 4:13-cv-02009 Document 2-3 Filed in TXSD on 07/10/13 Page 4 of 54 

UNITED STATES
 

v. 

SHELL OIL COMPANY, ET AL. 

APPENDICES TO CONSENT DECREE 

APPENDIX 2.3 

METHODOLOGY FOR CALCULATING 

REFINERY FLARING LIMITATION (INCLUDING 

SDP’S FORM EIA-820 FOR REPORT YEAR 2012) 
APPENDIX 2.3

ulation Basis

Refinery Crude

Capacity (b/cd)

Refinery

ComplexityZ US Complexity2

Refinery/US

Complexity

30-Day Rolling

Average SCFD

365-Day Rolling

Average SCFD

GJ (b/cd)1 327,000 11.33 11.32 1.001 2,455,944 1,637,296

r day (b/cd) are shown on the next page. US capacities as of 1/1/2012 as taken from US EIA report "U.S. Number and Capacity of

hed 6/22/2012) were used preferentially, see Attachment 1, along with the corresponding Shell Deer Park capacities as of 1/1/2012

 on Form EIA-820 Annual Refinery Report Parts 5 and 6. See Attachment 2. For processes where US capacities were not included on the US

Worldwide Refining Survey (published 12/5/2011) calendar day capacities were used for both the US and Shell Deer Park. See Attachment

available in the EIA report, barrels per stream day (b/sd) data from EIA report were converted to b/cd for some processes using O&GJ

llation and 0.9 for any other processes) where noted.

 are shown on the next page, and are specified in CD Appendix 1.14

Page 1

Case 4:13-cv-02009 Document 2-3 Filed in TXSD on 07/10/13 Page 5 of 54 
APPENDIX 2.3

Nelson

Complexity

Factors

SDP Capacity as of

1/1/2012 (b/cd,

except H2 and S)

SDP Capacity as of 1/1/2012 Source

(Notes 1, 2 & 3)

US Capacity as of

1/1/2012 (b/cd, except

H2 and S)

US Capacity as of 1/1/2012 Source

(Notes 1, 2 & 4)

1 327,000 Part 5, SDP's 2012 EIA-820, b/cd 17,322,178 EIA Website 2012 Data, b/cd

1.3 171,000 Part 6, SDP's 2012 EIA-820, b/sd*0.95 8,245,661 EIA Website 2012 Data, b/sd*0.95

7.5 83,600 Part 6, SDP's 2012 EIA-820,. b/cd 2,499,293 EIA Website 2012 Data, b/cd

6 63,600 Part 6, SDP's 2012 EIA-820, b/cd 5,611,191 EIA Website 2012 Data, b/cd

6 4,500 Part 6, SDP's 2012 EIA-820, b/sd*0.9 76,401 EIA Website 2012 Data, b/sd*0.9

5 65,600 Part 6, SDP's 2012 EIA-820, b/cd 3,246,874 EIA Website 2012 Data, b/cd

8 55,000 Part 6, SDP's 2012 EIA-820, b/cd 1,706,540 EIA Website 2012 Data, b/cd

2.5 337,050 Part 6, SDP's 2012 EIA-820, b/sd*0.9 14,908,736 EIA Website 2012 Data, b/sd*0.9

10 17,600 0&GJ (12/5/2011), b/cd 1,142,127 O&GJ (12/5/2011), b/cd

1000 92 O&GJ (12/5/2011), mmscf/cd 4,045 O&GJ (12/5/2011), mmscf/cd

240 1,011 O&GJ (12/5/2011), t/cd 32,284 O&GJ (12/5/2011), t/cd

2.75 0 Part 6, SDP's 2012 EIA-820, b/sd*0.9 14,400 EIA Website 2012 Data, b/sd*0.9

10 00&GJ (12/5/2011), b/cd 74,810 O&GJ (12/5/2011), b/cd

20 0 O&G1 (12/5/2011), b/cd 464,639 O&GJ (12/5/2011), b/cd

3 0 O&GJ (12/5/2011), b/cd 678,777 O&GJ (12/5/2011), b/cd

10 0 O&GJ (12/5/2011), b/cd 32,250 O&GJ (12/5/2011), b/cd

60 0 O&GJ X12/5/2011), b/cd 193,100 O&GJ (12/5/2011), b/cd

1.5 0 O&GJ (12/5/2011), b/cd 490,817 O&GJ (12/5/2011), b/cd

11.33 1132

alendar day (b/cd) are shown. US capacities as of 1/1/2012 from US EIA report "U.S. Number and Capacity of Petroleum Refineries"

le at www.eia.gov) were used preferentially, see Attachment 1, along with the corresponding Shell Deer Park capacities as of 1/1/2012

orm EIA-820 Annual Refinery Report Parts 5 and 6, see Attachment 2. For processes where US capacities were not included on the US EIA

 7 of EIA-820 rather than Part 6), Oil &Gas Journal Worldwide Refining Survey (published 12/5/2011) calendar day capacities were used for

see Attachment 3. Where b/cd data was not available in the EIA report, barrels per stream day (b/sd) data from EIA report were converted

 O&GJ factors (0.95 for vacuum distillation and 0.9 for any other processes) where noted.

Gas Journal Worldwide Refining Survey (published 12/5/2011) of petroleum refinery capacities as of 1/1/2012. See Attachment 3.

820 = U.S. Energy Information Administration Form EIA-820 submitted by Shell Deer Park. See Attachment 2.

 US Energy Information Administration Website (www.eia.gov), Number and Capacity of Petroleum Refineries data for the year 2012. See Attachment 1.

Page 2

Case 4:13-cv-02009 Document 2-3 Filed in TXSD on 07/10/13 Page 6 of 54 
APPENDIX 2.3

ATTACHMENT 1

Case 4:13-cv-02009 Document 2-3 Filed in TXSD on 07/10/13 Page 7 of 54 
U.S. Number and Capacity of Petroleum Refineries

elaU S. Energy Information

Administration

PETROLEUM &OTHER LIQUIDS

Page 1 of 2

OVERVIEW DATA ANALYSISBPROJECTIONS GLOSSARY> FAQS>

Number and Capacity of Petroleum Refineries

Area: U.S. Period: Mnual (as of January 1)

F D U~Series C' Arcs I ~ ~cbar ' 200 2000 I 2009 I 2010 2011 2012 I H sit ry

Total Number of Operable

Refineries ~_ 149 150 150 148 148 144 tse2-2ot2

Operating _ 145 146 141 137 137 134 tse2-2012

Idle 4 4 9 11 11 10 1 - 0~

tmoap er P. t~

3

Operable (Barrels per Calendar

Day) .... 17,443,492 17,593,847 17,671,550 17,583,790 17,736,370 17,322,178 19820012

Operatin8 16,997,792 17,225,797 17,313,550 16,850,194 16,937,024 16,744,291 ~sa2-202

Idle ~_' 445,700 368,050 358,000 733,596 799,346 577,887 1982-202

Operable (Barrels per Stream Day) ~.:_ 18,425,322 18,558,022 18,681,308 16,581,089 18,953,189 18,560,350 1982-202

Operating __ I ~_, 17,928,522 18,174,072 18,300,358 17,808,082 16,109,882 17,945,443 1982-2012

Idle ~ ; 496,800 383,950 380,950 773,007 843,307 614,907 1982-2012 ..~

( 5, _ may ..

Vacuum Distillation ~] 8,251,451 .. 8,0.20,501 8,542,261 8,542,643 8,650,243 8,679,643 1 8 - 1

Thermal Cracking ~~'• 2,564,080 2,606,260 2,639,090 2,631,676 2,672,376 2,763,356 1982.2012

Total Coking ~__I 2,537,480 2,579,660 2,612,490 2.605,076 2,645,776 2,736,756 taa74o~2

Delayed Coking J 2,331,580 2,374,280 2,454,590 2,500,676 2,486,876 2,577,856 7 e9 7-202

Fluid Coking ,_, 205,900 205,400 157,900 104,400 158,900 158,900 1987-zot2

Visbreaking ~..1 16,000 16,000 16,000 16,000 16,000 18,000 X987-2ot2

Other (Including Gas Oil) ` ~i 1D,600 10,800 10,600 10,600 10,600 10,600 1987.2072

Catalytic Cracking -Fresh Feed 8,216,957 6,265,697 6,291,871 6,140,121 6,219,721 6,032,512 ~se2-2oi2

Catalytic Cracking - Recycle Fead g2,04D 78,74D 78,740 91,840 95,640 84,890 1a 2-2 7

Catalytic Flydro-Cracking 1,790,682 1,770,325 1,743,300 1,819,700 1,855,600 1,879,600 ~9e2-2012

Distillate 602,800 556,900 593,100 595.200 540,100 596,500 2004.2072

Gas Oil 967,482 1,004,425 1,010,200 1,079,500 1,170,500 1,161,100 20W-2012

Residual 200,400 209,000 140,000 145,000 145,000 122,D00 2004.2012

Catalytic Reforming 3,907,310 3,891,938 3,629,338 3,700,483 3,720,613 3,641,813 198 - 012

Low Pressure 2,354,950 2,402,350 2,397,750 2,322,700 2,390,950 2,347,850 1987-2012

High Pressure 1,552,560 1,489,588 1,431,588 1,377,763 1,329,663 1,293,963 1987.2012

Catalytic

HydrotreaGng/Desulfurization 15.447,136 15,807,478 16,130,823 16,023,206 16,682,897 16,565,262 1982-2012

Naphtha/ReformerFeed 4,453,890 4,348,590 4,334297 4,281,446 4,441,323 4,360,593 19874012

Gasoline 2,221,568 2,420,968 2.415,282 2,394,882 2,578,782 2,519,082 2004202

Heavy Gas Oil __~ 2,578,840 2,672.440 2.735,538 2.796.798 2.809,298 2.877.138 1987.2012

Dlstiilate Fuel Oil 5,212,367 5,462,849 5,622,252 5,676,032 8.113,646 6,063,001 ]987.2012

Kerosene/Jet Fuel 1,009,450 1,137,010 1,160,110 1,339,150 1,484,850 1,489,750 2004-2012

piesel Fuel 3,332,671 3,466,471 3,551,211 3,647,211 3,917,611 3,961,411 2004.2012

OtherDislillate ~ 970,266 857,166 910,931 689,671 711,385 591,840 zoa•so~s

Residual Fuel OilJOther 980,451 902,831 1,023,454 874,448 739,648 745,448 1867.2012

Residual Fuel Oil ( 331,420 251,200 316,400 246,200 241,000 246,000 20042012

Other 649,031 651,631 707,054 628,248 498,648 498,448 ZOPa"20~2

http://www.eia.gov/dnav/pet/pet~np_capl_dcu_nus_a.htm 4/25/2013

Case 4:13-cv-02009 Document 2-3 Filed in TXSD on 07/10/13 Page 8 of 54 
U.S. Number and Capacity of Petroleum Refineries

Fuels Solvent Deasphalting ~ 7 379,290' 378,3501 380,950 383,250 382,750 374,550 1987-2072

~,

Catalytic Reforming (~ i 3,378,641 3,348,457 3,246,67412oaa2o~2

Toted Coking ~ 2,359,318, 2,390.223; 2,428,981 2.387,886. 2.396,787 2,499,293, s1 87.2012

Catalytic Cracking -Fresh Feed ` ' 5,830,486 5.853,656 5,847,130 5,675,830 5,794,214 5,611,191 1987-2012

CatalyticHydro-Crackln8 ~. J 1,620,705] 1,602,431 1,592,973 1,663,115 1,687,745 1,706,540 1987-2012

-= No Data Reported; — =Not Applicable; NA =Not Available; W =Withheld to avoid disdosure of in~vitlual company daha.

Notes: Idle refineries represent refineries where disfilla6on uni4s were wmpleiely idle but not permanently shuMam as of January 1 of the year. See

Definitions, Sources, and Nofes link above for more iMortnation on this table.

RBIBaSe Dffie: 6/22/2012

Next Release Date: 8/21/2013

Page 2 of 2

http://www.eia.gov/dnav/pet/pet_pnp_capl_dcu_nus_a.htm 4/25/2013

Case 4:13-cv-02009 Document 2-3 Filed in TXSD on 07/10/13 Page 9 of 54 
APPENDIX 2.3

ATTACHMENT 2

Case 4:13-cv-02009 Document 2-3 Filed in TXSD on 07/10/13 Page 10 of 54 
U.S. Energy Information ela Administration

OMB No. 1905-0165

Expiration Date: 1/31/20131

Version No.2010.02

FORM EIA-820

ANNUAL REFINERY REPORT

REPORT YEAR 2012

report is mandatory under the Federal Energy Administration Act of 1974 (Public Law 93-275). Failure to comply may result in criminal fines, civil penalties and

- sanctions as provided by law. For further information concerning sanctions and data protections see the provision on sanctions and the provision concerning the

9entiality of information in the instructions. Title 18 USC 1001 makes it a criminal offense for any person knowingly and willingly makes to any Agency or

irtment of the United States any false, fictitious, or fraudulent statements as to any matter within its jurisdiction.

- - - - - _..

;T 1. RESPONDENT IDENTIFICATION DATA PART 2. SUBMIS510NIRESUBMlSSION INFORMATION

~EIA ID NUMBER: ~ 1339570101 ~~

If any Respondent Identification Data has changed since the last report,

enter an "X" in the box:

Company Name: Shell Oil Co.

Doing Business As:

Site Name: DEER PARK REFG LTD P7NRSHP

Terminal Control Number (TCN):

Physical Address (e.g., Street Address, Building Number, Floor, Suite)

HWY 225

City DEER PARK State: TX - Z~p~ 77536 - 0100

(Mailing Address of Contact (e.g., PO Box, RR): If the physical and

malting addresses are the same, only complete the physical address.

P.O. BOX 100

City DEER PARK State: TX Zip: 77536 - 0100

If this is a resubmission, enter an "X" in the box:

A completed form must be received by February 15 ~n of the

designated report year.

Forms may be submitted using one of the following methods:

Email: OOG.SURVEYS~eia.gov

Fax: (202)586-1076

Secure File Transfer:

https:/lsignon. eia. doe.gov/upload/n oticeooa. i s q

Questions? Call: 202-588-6281

Contact Name:

Phone No.: ~ Ext: ~

Fax No.:

Email address:

Comments: Explain any unusual or substantially different aspects of your current year's operations that affect the data reported. For example, note new

processing units, major modifications or retirement of processing unib, sale of refinery, etc. (To separate one comment from another, press ALT+ENTER)

Case 4:13-cv-02009 Document 2-3 Filed in TXSD on 07/10/13 Page 11 of 54 
~~ _ :.....:... . ... :.. ~ ,;. OMB No. 1905-0165 ~~U.S. F.nergy Information Expiration Date: 1/31/2013

Administration Version No.:2010.02

FORM EIA-820

ANNUAL REFINERY REPORT

REPORT YEAR 2012

~EIA ID NUMBER: 7339570101 RESUBMISSION:

3. FUEL. ELECTRICITY. AND STEAM PURCHASED ~ CONSUMED AT THE REFINERY DURING 2011

PART 5. ATIIMOSPHERIC CRUDE OIL OISTtLLATION CAPACITY AS ~F JANUARY 1

Atmos heric Crude Oif Distillation Ca aci Code Barrel per Calendar Day2 Barrels per Stream Da

2012: O eratin 399 327000 327000

idle 400 0 0

Total O erable 401 327000 327000

2013: 0 erable 5o1 327000

z Barrels per Calentlar Day Operating, Idle and Total Operable Capacity (Codes 399, 400 and 401) must match the comparable capacity numbers reported on the Forth

EIA-810, "Monthly Refinery Report"filed for January 2012.

Case 4:13-cv-02009 Document 2-3 Filed in TXSD on 07/10/13 Page 12 of 54 
,. ,:,..,:., ~,;.,, ,,.,, ,~ ~,.,..

LJ.S. Energy Iiiformacion ela administration

FORM EIA-820

ANNUAL REFINERY REPORT

REPORT YEAR 2012

OMB No. 1905-016

Expiration Date: 1/31/201

Version No.:2010.02

EIA ID NUMBER: 1339570101 RESUBMISSION:

PART 6. DOWNSTREAM CHARGE CAPACITY ASOF JANUARY 1

Dovimstream Charge Capacity Code

2012

Barrels per

Calendar Day

2012

Barrels per

Stream Day

2013

Barrels per

Stream Day

Vacuum Distillation 402 180000 180000

Thermal Cracking:

Visbreaking 403 ~ 0

Fluid Coking (incl. Flexicokin) 404 0 0 0

Delayed Coking 405 83600 89300 89000

Other (incl. Gas Oil) 406 a 0

CatalyticCrackin ~'` j~~*'2- '' $

Fresh Feed 407 63600 70000 70000

Recycled 408 5000 5000

Catal tic Hydrocracking: ~`' ~' y~~ ` `''

Distillate 439 0 0 0

Gas Oil 440 55000 60000 60000

Residual 441 0 0 0

Desulfurization (including Catalytic HydrotreaYing): c ~ •.:~ .~ ,~^~~ ~~~s;

Na htha/Reformer Feed 426 75000 75000

Gasoline 420 42000 42000

Kerosene and Jet 421 40000 40000

Diesel Fuel 422 ~ 0

Other Distillate 423 45000 45000

Residual 424 49500 49500

Heavy Gas Oil 413 80400 80000

Other 425 43000 43000

Catal tic Reforming: _ ~

Low Pressure 430 42900 45000 45000

High Pressure 431 22700 24500 24500

Fuels Solvent Deasphaltin 432

PART 7. PRODUCTION CAPACITY AS OF JANUARY 1 Barrels er Stream Da , Exce Whet~e Noted

Rroduction Ca aci Code

2012 2013

Alk later q~5 18500 18500

Aromatics 437 ~ 0

As halt and Road Oil 931 ~ ~

{sobutane C4) 644 ~ ~

Isa entane (C5 , Isohexane C6 438 ~ ~

Isooctane C8} 635 ~ ~

Lubricants 85a ~ ~

Petroleum Coke - Marketable 02~ 38701 38701

H dro en million cubic ft. per day) 091 ~~$ goo

Sulfur (short tons per da) 435 1085 1085

Case 4:13-cv-02009 Document 2-3 Filed in TXSD on 07/10/13 Page 13 of 54
APPENDIX 2.3

ATTACHMENT 3

Case 4:13-cv-02009 Document 2-3 Filed in TXSD on 07/10/13 Page 14 of 54
.~.

~+

G7

y

0

1

m

~O

n

O

2011 Worldwide Refinin Surve

Leena Koottungal g Y

Survey EditorJNews Writer

All figures in barrels per calendar day (b/cd)

LEGEND

Numbers identify+procasses in table

Coking Catalytic reforming

1. Fluid. coking 1. Semiregenerative

2. Delayed coking 2. Cyclic

3. Other 3. Continuous regen.

4.Other

Thermal process

1. Thermal cracking Catalytic hydrocracking

2. Visbreaking 1. Distillate upgrading

2. Residual upgrading

Caffilytic cracking 3. Lube oil manufacturing

1. Fluid 4.Other

2. Other c. Conventional (high pressure)

hydrocracking: (>100 Barg or

1,450 psig)

m. Mild to moderate hydrocracking (<100 barg or 1,450 psig)

Catalytic hydrotreating

1. Pretreatment of cat reformer feeds

2. Other naphtha desulfurization

3. Naphtha aroma#ics saturation

4. Kerosine/jet des~ifurization

5. Diesel desulfurization

6. Distillate aromatics saturation

7. Other distillates

8. Pretreatment of cat cracker feeds

9. Other heavy gas oil hydrotreating

10. Resid hydrotreating

11. Lube oil polishing

12. Post hydrotreating of FCC naphtha

13.Other

Ablation Isomerization 

1, ulfuric acid 1. C4 feed 

2. Hydrofluoric acid 2. C~ feed 

3. C5 and C6 feed 

Polymerization/Dimerization 

1. Polymerization Oxygenates 

2. Dimerization 1. MTBE 

2. ETBE 

Aromatics 3. TAME 

1. BTX 4. Other 

2. Hydrodealkylation 

3. Cyclohexane

4. Cumene

NOTES

A Naw I Previously listed as SK Corp. Q Plans to sell

B Previorsly Natei as Oerrml Cap. 1 Preriously listed as Hyundai Oil Relinery Co. R Previously listed as Sunoco Inc.

C Preciously lined UJL Ltd. K Previousty listed as Hally Corp. 5 Plans io convert to a storage facifry

D Prerionary luted n 116E Rd~ 8 Mandxlnri~ L New to survey T Po~ sale

E Previoudy lists ~ Mxpay 8A USA Mc. M Shui down U Previously listed as Valero Energy Carp.

F May convert into a kd'u~patkrnio~ N Previousty listed as Frontier Oil Cary. V Pteviousfy listed as Marathon Petroleum C

i Whd 0 Preriously listed as frontier Refining Mc. W Previously listed as Shelt oeuisch4and Oii 

H Preria~slq IaEnd x Oil 145aetia ldl. P Previousty listed as ConacoPhillips

Capacity d~inilioas

Capacity expressed in bagels per calendar day (b/cd) is the maximum

number of barrels of input that can be processed during a 24-hour period,

after making apowances for the folbwing: (a) Types and grades of inputs

to be processed, (b) Types and grades of products to be manufactured, (c)

Environmental constraints associated with refinery operations, (d) Scheduled

downtime such as mechanical problems, repairs, and slowdown. Capacity

expressed in barrels per stream day (blsd) is the amount a unit can pTncess

when 'running at full capacity under optimal feedstxk and product slate

conditions. An asterisk (') beside a refinery location indicates that the number

has been converted from Wsd to b/cd using the conversion factor 0.95 for

crude and vacuum distillation units and 0.9 for all downstream cracking and

conversion units.

REFINERY REMOVALS

HydroQan:

Hydrogen volumes presented here represent either generation or

upgrading to 9Q+% purity.

Name Location Country Cords hkd Reason

Western Refiring Yorktown, Virginia US 70,000 Shu[ down

Suraco Inc. Westville, NJ US 15 ,000 Shu[ down

Abn USA Bakersfield, CaliL US 70,000 Integrated wAh Paramount refinery

Hilly Cap. Tulsa, Okla. US 85,OIX1 IMegtffied wdh other Tulsa refinery

i~ai SA Dunkirk France 137,028 Shut dwm

Pak-Arch Rdinery Co. Mahmaad Kot, Punjab Pakistan 1{)0,000 Shut cam

PeVoplus Hok3ir~s AG Cressier Switrarlar~ 6D,000 Shut dawi

Catalytic reformi~:

1. Semiregenerative reforming 

reforming unit at specked in

for in sihi catalyst regenerati

2. Cyclic regeneraUott reformin

tinual regeneration of catalys

that can be isolated from an

This is accomplished withou

3. Continuous regeneratbn ref

addition of this regenerated 

4. "Other" includes nonregener

fresh catalyst) and moving-b

Case 4:13-cv-02009 Document 2-3 Filed in TXSD on 07/10/13 Page 15 of 54
0 Worldwide Refineries-Capacities as of Jan. 1, 2012

~ Charge capacih~ ~d --- Production capacity, Wc

m

~'

No. of Vaeuun Thermal Catalytic Catalytic Catalytic Catalytic

Country 0 ~oaies pMe distillalin~ Cotina operations cracking refaming hydrocraching hydrolreating Alkylatian PoIJDim. Nomatics Isoraerizadon tubes Oxygen

c

Albania ......... . ... 2 26,300 10,500 12,000 - - 3,500 - 17,400 - - 600 - 700 - 

~ Algeria ............. 4 450,OW 10,894 - - - 88,900 ' - 81,950 - - -- - - - 

~ Angola ............. 1 39,000 2,500 - - - 1,900 - 6,600 - - - - - - 

~ Argentina ........... 10 630,575 248,365 91,233 38,420 141,180 56,530 IJ,~00 175,600 4,300 520 - 12,700 7,290 2,60

~ Aruba . . . . . . ........ 1 235,000 166,250 68,406 30,600 - - - 214,200 - - - - - - 

Australia............ 7 760,1A8 192,865 - - 235,043 172,053 18,407 543,531 24,734 10,609 1,000 39,606 - - 

~ Austria ............. 1 208,600 65,000 - 16,875 26,250 32,725 - 139,400 - - - 14,400 - 1,6

p Azerbaijan..:.......; 2 398,978 237,200 38,524 - 57,756 24,466 - fi7,492 - 930 - - - 16,200 - 

~ Bahrain ............ 1 253,650 198,170 - 21,600 35,100 13,500 54,000 76,500 - 3,330 - - - - 

Bangladesh.......... 1 33,000 4,000 - 10,000 - 1,800 1,200 2,000 - - - - - - 

Belariu ............. 2 A93,323 105,800 - 60,000 44,006 92,000 30,000 262,100 - - 2,785 4,500 3,766 - 

Belgium ............ 4 739,821 250,630 - 30,016 133,553 105,589 - 687,755 17,630 - - 0 - 3,75

Bolivia ............. 2 41,200 2200 - - - 12,100 - 6,899 - - - - - - 

Brazil .............. 13 1,917,333 810,140 115,319 9,800 545,287 24,386 - 284,446 b,290 - - - 20,009 6,46

Brurrei ............. I 8,600 - - - - 5,700 - - - - - - 

Bulgaria . , .......... I 115,240 49,900 - 20,600 23,300 4,060 - 64,2(10 2,600 - 2,000 - - 79

Cameroon........... I 37,000 - - - - 6,500 - 16,140 - - - - - - 

Canada ............. 17 1,918,455 645,056 59,100 121,430 482,468 354,930 210,374 1,383,536 70,403 19,240 62,689 62,490 3,000 - 

Chile .............. 3 226,800 85,050 13,860 13,860 50,540 26,460 50,400 - 910 - - 8,510 - 1,58

China . ...... . .. . . . . 54 6,866,000 240,WQ 156,000 - 588,000 178,000 185,000 541,000 15,500 - 21,000 - 18,000 90

China, Taiwan ........ A 1,310,000 248,5Q6 51,000 - 217,900 115,000 25,000 672,500 1A,200 - 14,400 26,000 15,3 11,26

Calanbia .....,..... 5 290,850 141,000 - 52,OOD 90.000 - - 19,0 2,100 2,100 2,200 - 1,400 - 

Cor~o (&aznaille) .... 1 21,000 8,000 - - - 2,000 2,000 3,500 - - - - - - 

Costa Rica .......... 1 24,000 600 - 6.500 - 1~2t}0 - 2.000 - - - - - - 

Croatia ...... . . ... . . 3 250,317 87,040 5,000 23,526 51,002 49,368 12264 b8,256 - - 9,438 5,431 470 - 

Caba .............. 4 301,400 75,700 - - 14,7W 20,000 - 55.850 - - - - - - 

Czech Republk....... 3 183,000 78,870 - 17,000 - 27,470 34,430 143,78a - - 660 7,210 2,1811 2,16

Denmark... , .......: 2 174,400 22,000 - 64,550 - 21,990 - 42,760 - - - 6,400 - - 

Dominican Repudic ... 2 50,000 - - - - 8,200 - 20,813 - - - - - - 

Ecuada,........... 3 176,000 45,300 - 31,500 18,000 12,800 - 24,500 - - - - - - 

Egypt .............. 9 726,250 95,200 39,270 - - 62,240 33,50Q 207,802 9,000 - 1,584 10,700 4,441 - 

EI Salvador.......... 1 Y1,000 4,000 - - - 3,000 - 15,50D - - - - - - 

Eritrea ............. 1 14,564 2,219 - - - 1,465 - 2,742 - - - - - - 

Finland ............. 2 2fi0,575 14fi,085 - 34,424 56,690 50,060 90,110 298,325 7,750 64Q - - 5,280 5,73

France ...... . ..... . 12 1,718,803 715,200 - 146,872 347,052 256,669 71,845 1,233,048 26,7Q2 2,968 2,887 48,432 36,390 4,71

Gabon ............. 1 24,000 - -- 9,220 - 1,40 - 9,430

Germany............ 15 2,417,162 1,09fi,231 105,809 247,445 349,171 404,822 263,067 2,011,782 30,885 8,301 71,944 94,226 14,220 13,17

Ghana ............. 1 45,00 - - - 14,000 65~W0 - - - - - - - - 

Greece . ............ 4 423,000 152,D00 - 49,000 75,550 49,240 43,900 361,635 2,4W 1,720 9,1Q0 23,650 3,500 3,94

Hungary............ 1 161,00 77,500 16,900 14,Ob0 24,000 29,600 - 120,700 3,300 - 12,000 3,500 6,100 1,20

India .............. 2i 4,042,761 811,986 169,625 93,180 531,305 51,673 165,640 250,742 85,000 - 9,742 - 8,240 1,34

Inda~esia........... 8 1,011,925 265,980 32,580 58,860 101,450 92,970 99,720 23,430 16,200 - - - - - 

Iran .............. . 9 1,451,000 559,400 - 240,800 35,00 164,700 13b,500 183,160 - - - - 19,60 - 

Iraq ............... 9 637,500 145,000 - - - 88, 00 J4,241 292,000 - - - 2,500 9.426 - 

Ireland ....... . ..... 1 71,400 - - - - 11,000 - 44,6i~ - - - 7,600 - - 

lsrael .............. 2 220,400 115,000 - 66,000 49,504 26,500 - 96,0(30 - 2,200 - - - 75

Itaty ............... 17 2,337,229 814,237 45,000 448,204 321,506 287,Q69 303,210 1,250,753 48,334 1,500 13,40D 112,260 24,000 11,7

lvay Coast .......... 1 63,990 23,990 - - - 12,330 14,480 27,310 - - - - - - 

Jamaica ............ 1 36,000 1,800 - - - 3,700 - 23,8W - - - - - - 

Japan .............. 30 4,729,890 1,764,195 123,400 20,00 986,980 829,225 181,640 5,016,160 74,690 5,760 207,467 31,350 38,013 2,97

Jordan ............. 1 90,400 21,500 - - 4,000 10,900 5,220 17,300 - - - - - - 

Karakhs#an.......... 3 345,D93 121,037 24,997 52,071 38,356 51,586 - 117,890 - - - - - - 

Kenya .............. 1 90,D00 1,700 - - - 8,260 - 36,000 - - - - - - 

K~wdit ............. 3 936,000 327,750 72,000 - 36,060 46,620 115,650 588,780 5,filb - - - - 6,56

Kyrgyzstan .......... 1 10,000 - - - - 

Li6eria ............. 1 15,000 1,000 - - - 2.000 - 3,300 - - - - - - 

Libpa .............. 3 378,D00 3,715 - - - 2Q,250 - 43,330 - - - - b35 - 

Lithuania ........... ~ 1 19i1,IX10 89,300 - 28,800 43,200 45,A00 - 153,900 -- 7,200 - I8,9U0 - 2,7

Macedon~ .......... 1 50,0 - - - - 10,860 - 22,050 - - - 4,390 - - 

Malaysia............ 7 538,582 94,335 24,0(10 - 42,700 75,070 36,000 216,801) - - - 10,800 - - 

Case 4:13-cv-02009 Document 2-3 Filed in TXSD on 07/10/13 Page 16 of 54
0

H

0

w

O

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O

ti

Worldwide Refineries-Capacities as of lan. 1, 2012

~ «P~h ~~ Protl~ction capacity

No. M Vacuum Thermal Catalytic Catah►lic CatatyGc Catatytic 

CouMty Mine~ia Cede distlllation CoNina operations cracking rehming hytlracracking hydrotreating Alkylatian PolJDim. Aromatics Isomerizalion Lu6es Oxygena

Martinique .......... 1 17,329 - - - - 2,862 - 14,269 - Mezico ............. fi 1,5d0,000 754,000 191,000 - 380,500 279,300 - 926,050 128,456

Morocco............ 2 154,901 24,921 - - 5,046 24,359 - 35,539 - Myanmar ........... 3 57,000 4,400 5,200 - - - - - - Netherlands ......... 6 1,196,571 711,045 41,500 41,4U4 101,983 148,616 198,071 1,016,234 15,450

Netherlands Antilles ... 1 320,000 195,000 - 80,000 50,000 20,000 - 119,500 9,OW

New Zealand......... 1 107,000 38,274 - - - 25,840 30,0, 104,490 - Nicaragua........... L 24,000 1,500 - - = 3,000 - 14,5 - Nigeria ............. 4 445,000 124,490 - - 82,7oQ 70,070 - 1D9,231 9,870

North Korea ......... 2 71,W0 - - - - 7,300 - 7,400 - Naway ............. 2 314,IXI0 - 24,78D 32,000 49,OOQ 34,900 - 126,OIJQ - Oman .............. 1 65,000 - - - - 16,000 - 21,000 - Pakistan............ b 186,306 19,815 - - - 11,650 - 54,870 - Papua New Gaines .... 1 32,500 - - - - - - - - Paraguay............ 1 7.500 - - - - - - - - PBN ............... G 198,950 94,000 - 25,700 33,500 2,100 - 2,800 ~ - Philippirres...,...... 3 273,000 61,000 - 33,000 19,D00 51,000 - 184,990 - Paland ............. 4 492,950 265,123 - - 32,485 67,514 145,908 259,5W 3,372

Portugal........,,.. 2 304,172 87,785 - 36,540 40,50Q 50,182 9,180 201,537 5,400

Puerto Rico.......... 1 73,000 34,000 - - - 21,000 20,000 21, 0 - Qatar .............. 2 338,700 - - - 60,00 29,400 20,D00 39,350

Romania............ 10 537,277 273,225 68,240 37,577 109,478 61,763 1,534 237,625 2,300

Russia ............. Atl 5,430,908 2,028,570 84,999 382,593 330,817 745,735 57,056 2,170,966 10,006

Saudi Arahia......... 7 2,112,000 445,950 - 138,200 1Q3,600 193,160 133,820 493,460 31,5{10

Senegal........,,.. 1 25,030 7,160 - - - 1,590 - 1,930 - S~bia & Montenegm... 2 214,826 50,583 - 20,340 18,95Q 18,822 - 5D,910 3,070

Sierra Leone......... 1 10.000 - - - - - - - - Singapore........... 3 1,357,000 346,000 - 203,710 80,000 146,47Q 129,360 76,500 9,00

Slovakia ............ 1 115,000 55,000 - - 18,0 21,000 42,000 87,800 4,500

Slovenia ............ 1 13,500 - - - - - - - - Sauth Afica .. , , ..... 4 4&4,547 2U1,375 26,800 66,000 108,644 77,142 11,774 227,772 9,595

South Korea ......... 6 2,759,500 515,650 19,000 - 314,000 342,000 326,500 1,450,380 48,700

Spain .............. 9 1,271,500 A14,2A5 61,100 149,200 141,300 196,750 131,500 825,380 16,916

Sri Lanka ........... 1 50,000 24,000 - 12,506 - 5,300 - 19,295 - Sudan ............. 3 121,700 - - - - 1,906 - 8,100 - Suriname ........... 1 7,000 7,000 - 2,8Q0 - - - - - Sweden ............ 5 437,000 135,60D - 66,8 29,7 70,66D 48,600 268,540 - Switeerland.......... 1 72,000 - - - 2~,4~ 12,400 - 33,200 - Syria ...... . ....... 2 239,865 63,135 18,200 22,689 - 31,242 2b,0.10 80,866 - Tanzania............ 1 14,900 - - 2.500 - 2,5D0 - 4,A00 - Thailand............ 4 584,250 202,500 - 16,983 91,990 47,770 43,073 428,634 - Trinidad &Tobago ..... 1 168,D00 114,2D0 - 24,W0 24,000 18,000 45,000 41,004 1,200

Tunisia ............. 1 34~OD0 - - - - 3300 - - - Turkey ............. 6 714,275 201,767 - 23,590 28,935 65,662 53,820 265,5 - Turkmenistan ........ 2 236,970 91,645 28,568 - 15,151 52,540 - 63,500 1,028

Ukraine ............ 6 874,759 336,297 22,149 17,241 7Q,100 144,711 7,200 315,013 - United Rrab Emirates... 5 773,250 92,870 - - 34,350 25,875 31,050 158,627 1,140

United Kingdom ... , .. 1D 1,767,168 866,314 64,600 106,958 444,723 339,771 36,000 1,271,541 92,202

UniledStates........ 125 17,787,714 7,909,865 2,543,248 34,020 5,649,&54 3,492,288 1,726,030 14,061,515 1,142,127

Uruguay............ I 50,000 25,000. - 7,OIX1 12,OW 12,000 - 23.000 - Uzbekisfan .......... 3 224,271 45,671 17,667 9,585 - 23,487 - 30,804 - Yenezuela........... 5 1,282,100 585,78U 144,90Q - 231,800 49,500 - 389,700 65,8fl0

dietnam ............ 1 140,000 - - - - - - - - Virgin Islas . , ...... 1 500,0 0 205,000 55,000 37,006 140,000 105,OW - 435,000 18,000

Yemen ............. 2 140,000 10,500 - - - 14,5~d - - - Zambia ............. Z 23,750 2,280 - - - 5,320 - 8,550 - Tof~l ................ 655 88,055,552 29,062,134 4,681,013 3,801,129 14,693,328 11,468,147 5,488,694 45,73Q,072 2,090,102 - 17,000 - 16,600 15,49

- - - 2,460 - - - - 50D - - 68,968 8,730 11,600 2,71

2,OW - - 12,000 - 

- - - - . - 

2,274 291 3,610 3,878 - 

- 1,000 - - 1,0

11,~00 - 3,840 - - 

- 1,400 - 3,800 - 

- - - - - 

- - 1~,00~ 3,7~ - 

- 10,262 23,194 17,796 2,51

- 17,216 - - - 

- - - - - 

- - 25,000 - - 

- 7,801 3,846 10,366 1,3

1,729 54,337 21,869 82,842 7,1

- 6,500 33,000 - 3,lO

- 200 - 300 

- 48,000 - 45,500 1,4- 9,250 6,000 2,W6 1,5

4,940 6,900 12,223 8,000 

- 140,300 - 66,640 10,5

- 25,800 36,000 9,604 4,fi

- - 

3,420 - 28,530 - 

3,8W - 6,40Q - 

- - 11,493 - 

- 9,500 19,596 - 

1,580 - - - 1,0

- - 14,055 5,870 

1,223 - - 2.000 

3,464 - 500 1

1,900 - - - 

13,596 14,590 120,423 23,894 3,9

74,810 4b4,639 678,777 193,100 32,2

- - 6~000 - 

- - - 9,347 

- 2,000 20,700 12,020 12,8

7,Op0 18,000 17,000 - 

- - - - 

- - - - 

195,320 1,371,875 1,~i,901 802,516 193,0

Case 4:13-cv-02009 Document 2-3 Filed in TXSD on 07/10/13 Page 17 of 54
UNITED STATES 

v. 

SHELL OIL COMPANY, ET AL. 

APPENDICES TO CONSENT DECREE 

APPENDIX 2.4 

CALCULATION OF OLEFINS FGRS ESTIMATED 

PERCENT RECOVERY 

Case 4:13-cv-02009 Document 2-3 Filed in TXSD on 07/10/13 Page 18 of 54
APPENDIX 2.4

CALCULATION OF OLEFINS FGRS ESTIMATED PERCENT RECOVERY

1. Calculation of Funrecovered for each hour:  Using each hourly average Adjusted Vent Gas Flow Rate

(“AVGFR”)  from the HFvg‐adjusted data set submitted pursuant to paragraph 46.b., calculate hourly

unrecovered gas flow (“Funrecovered” in KSCFH) due to the AVGFR exceeding operating compressor

capacity using the following assumptions:

a. At least one compressor is assumed to be running at all times.

b. When the hourly average AVGFR exceeds the capacity of the currently operating

compressor(s) (“Capop” in KSCFH), an additional compressor(s) up to the AVGFR begin(s)

operating the next hour. This accounts for the one‐hour lag in compressor start up time

allowed after the need for the compressor arises for those compressors required to be

Available for Operation.

c. As soon as the hourly reported flow rate does not necessitate one or more of the

compressors, that compressor(s) shuts off.

d. Each compressor and the overall FGRS recovers flow up to its design capacity during periods

when the flow exceeds such capacity.  Flow above currently operating compressor capacity

for each hour is considered unrecovered flow (Funrecovered) for that hour and, when AVGFR is

greater than Capop for an hour, is calculated as follows for that hour:

Funrecovered = AVGFR ‐ Capop

2. Calculation of Vdowntime:  The total volume of gas not recovered due to compressor downtime allowed

per the CD (Vdowntime, in KSCF), is calculated using the following assumptions:

a. Assume that the percentage of downtime for a specific compressor that will result in

unrecovered flow is the same as the percentage of overall allowed downtime for that

compressor (e.g., if a compressor is allowed to be down 2% of all time, and the compressor

is only ever needed for 100 hours over two years, then unrecovered flow due to downtime

will occur during 2% of 100 hours, or 2 hours).  In other words, assume compressor down

time is even distributed over time and does not all occur at times the compressor is needed.

b. For the compressor in each scenario that is allowed downtime per the CD, calculate the

average gas volume over the one year period, not the maximum gas volume, that would be

recovered by that specific compressor when needed (i.e., when flow exceeds capacity of

upstream compressors and the specific compressor is recovering flow).

c. Multiply the average gas volume recovered (“Vavg‐rec “) by the compressor when needed by

the total number of hours of allowed downtime (“Hd”) that occur when the compressor is

needed and sum for each hour of downtime:

Vdowntime  Hd

h =1

Hd

 x Vavg - rec

   

Case 4:13-cv-02009 Document 2-3 Filed in TXSD on 07/10/13 Page 19 of 54
APPENDIX 2.4

3. Calculate overall percent recovery over the one year time period (i.e., 8760 hours), according to the

equation (where “h” in the summation represents each incremental hour).

100%

AVGFR

V F

1 Recovery Percent Estimated 8760

1h

8760

1h

downtime dunrecovere







































A spreadsheet containing hypothetical examples/applications of the above methodology is set forth at the

following:  http://www2.epa.gov/enforcement/shell-deer-park-spreedsheet

Case 4:13-cv-02009 Document 2-3 Filed in TXSD on 07/10/13 Page 20 of 54
UNITED STATES 

v. 

SHELL OIL COMPANY, ET AL. 

APPENDICES TO CONSENT DECREE 

APPENDIX 2.5 

METHODOLOGY FOR CALCULATING THE 

365-DAY ROLLING SUM EMISSIONS OF 

VOLATILE ORGANIC COMPOUNDS FROM 

THE HIPA FLARE 

Case 4:13-cv-02009 Document 2-3 Filed in TXSD on 07/10/13 Page 21 of 54
APPENDIX 2.5

1 

Equations for Calculating the 365­day Rolling Sum Emissions of Volatile

Organic Compounds from the HIPA Flare

For the purpose of demonstrating compliance with the Volatile Organic Compound 

(“VOC”) emissions limit for the HIPA flare in Paragraph 49 of this Consent Decree, the 

block sum of HIPA Flare VOC emissions shall be calculated each day in accordance with 

the steps prescribed below, and the 365-day rolling sum, rolled daily shall be calculated 

using data from the prior 365 calendar days. All abbreviations, constants, and variables 

are defined in the “Key to the Abbreviations” on page 3 of this Appendix. An example 

calculation spreadsheet can be found at the following: 

www.epa.gov/enforcement/air/documents/sdp‐appendix2‐5.xlsx

Step 1: Determine the Molecular Weight (“MWi”) of each Volatile Organic

Compound (“VOC“) in the Vent Gas.

Take the MWi values for i= 8 through i=18 of each individual Vent Gas VOC from 

column i of Table 1 in Appendix 1.3. 

Step 2: Determine Compliance with the Net Heating Value of the Combustion Zone 

(“NHVcz”) standard for each calendar day. 

Determine for the 365-day rolling sum period the calendar days “r” during which the 

3-hour rolling average standard in paragraph 56.b was met, and the calendar days 

“s” during which the standard was not met. 

Step 3: Calculate the block sum mass of VOC emitted for each calendar day “r” (i.e., 

days during which the flare was operated in compliance with the Net Heating Value 

of the Combustion Zone standard (“ ”). 

Step 3a: The mass of VOC in the Vent Gas (“ ”) for each calendar day “r” 

shall be calculated as follows using daily block average values of and for 

that day: 





  

18

i 8 5.385

iivg

vgVOC

xMWQ

m Equation 1

Step 3b: The mass of VOC emitted for a calendar day “r” shall be calculated as 

follows using a 98% VOC Combustion Efficiency (“ ”) and the value for 

 from Equation 1: 

 Equation 2

 

NHVcz

(M  ̇ VOC Emit)r

m  ̇ VOC vg

Qvg

xi

CEVOC

m  ̇ VOC vg

(M  ̇ VOC Emit)r  m  ̇ VOC vg(1  CEVOC /100) 24

Case 4:13-cv-02009 Document 2-3 Filed in TXSD on 07/10/13 Page 22 of 54
APPENDIX 2.5

2 

Step 4: Calculate the block sum mass of VOC emitted for each calendar day “s” 

during which the Net Heating Value of the Combustion Zone standard was not met 

(“ ”) 

Step 4a: The mass of VOC in the Vent Gas shall be calculated for each 1-hour 

block sum period “j” of the calendar day “s” as follows using each hourly block 

average value for and that day: 





  

18

8 5.385 )(

i

iivg

jvgVOC

xMWQ

m Equation 3

Step 4b: Calculate NHVcz for each 1-hour block sum period “j” of the calendar 

day “s” (“ ”) using the equations in Step 6 of Appendix 1.3. 

Step 4c: Calculate the Combustion Efficiency of VOC for each 1-hour block sum 

period “j” (“ ”) of calendar day “s”: 

If < 95 BTU/scf: 

 = 0 Equation 4a

If 

 (CEVOC ) j  0.16  95  (NHVcz)  j

1 0.16  95  (NHVcz)  j

100 Equation 4b

Step 4d: The block sum mass of VOC emissions from the HIPA Flare during 

calendar day “s” shall be calculated as shown below in Equation 5 as the sum of 

the hourly block sum VOC emissions calculated for each hour “j” during that 

calendar day. 

 Equation 5

Step 5: Calculate the tons per year of VOC emissions (“ ”). 

The results of Equation 2 for each day “r” and Equation 5 for each day “s” of the 365-day 

rolling sum period are summed and converted to tons per year as per Equation 6 below. 

The result of Equation 6 is used to demonstrate compliance with the HIPA Flare VOC 

limit in the consent decree. 

(M  ̇ VOC Emit)s

Qvg

xi

(NHVcz) j

(CEVOC ) j

(NHVcz) j

(CEVOC ) j

  NHVcz j

 95 BTU /scf :

(M  ̇ VOC Emit)s  (m  ̇ VOC vg )j  1  (CEVOC ) j    /100 

j 1

24



TPYVOC Emit

Case 4:13-cv-02009 Document 2-3 Filed in TXSD on 07/10/13 Page 23 of 54
APPENDIX 2.5

3 

    Equation 6

Key to the Abbreviations: 

0.16 = CEVOC multiplier for NHVcz (unitless)

24 = Number of hours in a calendar day (24 hr/d)

95 = NHVcz below which CEVOC empirically correlates to zero (BTU/scf)

385.5 = conversion from pound moles to standard cubic feet (385.5 lb/scf) 

2000 = conversion from pounds to tons (2000 lb/ton)

CEVOC = percent combustion efficiency of VOC in the Vent Gas (%)

i = individual numbered compound from column i in Table 1 of Appendix 1.3 (unitless) 

j = individually numbered hours in a calendar day with NHVcz non-compliance (unitless)

= mass of VOC emitted for calendar day in NHVcz compliance (lb/d) 

 = mass of VOC emitted for calendar day with NHVcz non-compliance (lb/d)

 = calendar day average mass flow rate of VOC in the Vent Gas (lb/hr)

 = average mass flow rate of VOC in the Vent Gas during hour “j” (lb/hr)

MWi = molecular weight of individual compound (lb/lb-mole)

NHVcz = net heating value of the combustion zone (BTU/scf)

Qvg = vent gas volumetric flow rate (scfh)

r = calendar day when no exceedences of the standard occurred (unitless)

s = calendar day during which exceedence(s) of the standard occurred (unitless)

 = mass flow rate of VOC emissions (tons/yr) 

VOC = volatile organic compound in the vent gas (unitless)

xi = individual compound volume fraction in the vent gas (volume fraction)

 

TPYVOC Emit 

(M  ̇ VOC Emit)r  (M  ̇ VOC Emit)s

s

 r

2000

(M  ̇ VOC Emit)r

(M  ̇ VOC Emit)s

m  ̇ VOC vg

(m  ̇ VOC vg ) j

NHVcz

NHVcz

TPYVOC Emit

Case 4:13-cv-02009 Document 2-3 Filed in TXSD on 07/10/13 Page 24 of 54
UNITED STATES 

v. 

SHELL OIL COMPANY, ET AL. 

APPENDICES TO CONSENT DECREE 

APPENDIX 2.6 

MITIGATION PROJECT AT THE NORTH 

EFFLUENT TREATER 

Case 4:13-cv-02009 Document 2-3 Filed in TXSD on 07/10/13 Page 25 of 54
APPENDIX 2.6

MITIGATION PROJECT: NORTH EFFLUENT TREATER CONTROLS

2.6.1. By the dates set forth herein, SDP shall implement the Environmental Mitigation

Project described in this Appendix 2.6 for the purpose of reducing emissions of hazardous air

pollutants ("HAPs") and volatile organic compounds ("VOCs") from the North Effluent Treater

at the Covered Facilities.

2.6.2. Definitions

a. "Breakthrough" shall mean, for purposes of monitoring a carbon canister,

any reading equal to or greater than SO ppm VOC or 1 ppm benzene (depending upon the

parameter that SDP decides to monitor).

b. "DAF" shall mean the Dissolved Air Flotation unit that is located at the

North Effluent Treater and marked as such on the schematic attached as Exhibit 1.

c. "Manhole 4 Suxnp" shall mean the manhole at the North Effluent Treater

that is marked as "Manhole 4 Sump" on E~ibit 1.

d. "North Effluent Treater" or "NET" shall mean the wastewater treatment

plant located centrally at the north end of the SDP Refinery and Chemical Plant Facilities. It

treats wastewater from the Covered Facilities using primary, secondary, and tertiary treatment.

Treated water is discharged into the Houston Ship Channel. A plot plan showing the location of

the North Effluent Treater is attached as Exhibit 2.

e. "Trickling Filter Sump" shall mean the sump that is located downstream

of the Trickling Filter at the NET and marked as "Trickling Filter Sump" on Exhibit 1.

f. "Trickling Filter" shall mean the fixed-growth biological treatment unit

that uses aslime-covered stone filter packing to treat effluent from the DAF prior to further

biological treatment in the aeration basins at the NET. The Trickling Filter is marked as such on

E~ibit 1.

2.6.3. Objective. The objective of this Appendix is to reduce VOC emissions from the

Manhole 4 Sump, the DAFs, the Trickling Filter, and the Trickling Filter Sump. SDP requires

further time to study some of the options available to achieve this objective, but this objective

would be thwarted—and it would be a violation of the terms of this Appendix—if SDP merely

redirected the waste streams) from one or more of these four units to uncovered and/or

uncontrolled waste management unit(s).

2.6.4. Tricklin Fg filter. By no later than December 31, 2019, SDP shall permanently

take the Trickling Filter out of service by physically removing all connections that would allow

the Trickling Filter to be used. SDP shall complete taking the Trickling Filter out of service by

surrendering any permits to operate the Trickling Filter.

App. 2.6 page 1 of 4

Case 4:13-cv-02009 Document 2-3 Filed in TXSD on 07/10/13 Page 26 of 54
APPENDIX 2.6

2.6.5. Manhole 4 Sump and Trickling Filter Sump. By no later than December 31,

2015, SDP shall undertake all necessary modifications to the Manhole 4 Sump and the Trickling

Filter Sump such that each of them conforms to the requirements of 40 C.F.R. § 61.346(a). SDP

also shall install on each of these Sumps a closed vent system and control device that conforms

to the requirements of Paragraphs 2.6.6. and 2.6.7., respectively.

2.6.6. DAF. By no later than December 31, 2019, SDP shall undertake one of the

following actions at the DAF:

a. Undertake all necessary modifications to the DAF such that the DAF

conforms to the requirements of 40 C.F.R. § 61.347. Under this option,

SDP shall install on the DAF a closed vent system and control device that

conform to the requirements of Paragraphs 2.6.7. and 2.6.8., respectively.

b. Replace the DAF with a new dissolved air flotation unit that conforms to

the requirements of 40 C.F.R. § 61.347. Under this. option, SDP shall

install on the new dissolved air flotation unit a closed vent system and

control device that conform to the requirements of Paragraphs 2.6.7. and

2.6.8., respectively.

c. Remove the DAF permanently from service. If SDP elects to use this

option, SDP shall either:

Send the waste stream off-site, by means of a hard-piped

conveyance system, to afederally-permitted wastewater treatment

plant; or

ii. Ensure that the waste stream that no longer is directed to the DAF

is transferred to waste management unit that is covered and

controlled in conformance with 40 C.F.R. Part 61, Subpart FF.

2.6.7. Closed Vent System Requirements. For the Manhole 4 Sump, the Trickling Filter

Sump, and the DAF (to the extent it is either retrofitted with controls (¶ 2.6.6.a) or replaced with

a new DAF that is controlled (¶2.6.6.b)), SDP shall design, install, operate, and maintain a closed

vent system in conformance with 40 C.F.R. § 61.349(a)(1). The closed vent system shall

conform to all requirements of 40 C.F.R. § 61.349 related to closed vent systems.

2.6.8. Control Device Requirements.

a. General. SDP shall route all vapors from the closed vent systems required

pursuant to Paragraph 2.6.7. to one or more control devices, each of which is designed, installed,

operated, and maintained in conformance with 40 C.F.R. § 61.349(a)(2)(i) or (ii) or (iii). The

control devices) shall conform to all requirements of 40 C.F.R. § 61.349 related to control

devices.

App. 2.6 page 2 of 4

Case 4:13-cv-02009 Document 2-3 Filed in TXSD on 07/10/13 Page 27 of 54
APPENDIX 2.6

b. Carbon Adsorption System. To the extent that SDP installs a carbon

adsorption system as one or more control devices, SDP shall comply with the following

requirements:

i. Dual Canisters. SDP shall install primary and secondary carbon

absorption canisters and operate them in series (the "dual canister"

configuration). SDP may comply with the dual canister

configuration by using a single canister with a "dual carbon bed" if

the dual carbon bed configuration nonetheless allows SDP to be

able to monitor for breakthrough between the primary and

secondary beds consistent with Subparagraph 2.6.8.b.ii.

ii. Monitoring. After installation, SDP shall monitor for breakthrough

between the primary and secondary canisters/beds at times when

there is actual flow to the canisters/beds. Monitoring between the

primary and secondary canisters beds shall occur on a daily basis

or at intervals no greater than 20 percent of the design carbon

replacement interval, whichever is greater. SDP shall monitor the

outlet of the secondary canister/bed on a monthly basis or at its

design replacement interval (whichever is less) to verify the proper

functioning of the system.

iii. Replacement. SDP shall replace the original primary carbon

canisterlbed (or route the flow to an appropriate alternative control

device) immediately when breakthrough is detected. The original

secondary carbon canister/bed (or a fresh carbon canister/bed) shall

become the new primary canister/bed and fresh carbon canister/bed

will become the secondary carbon canister/bed. For purposes of

this Subparagraph, "immediately" shall mean eight (8) hours for

canisters/beds of 55 gallons or less; twenty four (24) hours for

canisters/beds between 55 gallons up to 20,000 pounds; and

forty-eight (48) hours for canisters/beds 20,000 pounds or larger.

iv. Maintaining Canister Supplies. SDP will maintain a supply of

fresh canisters/beds at the Covered Facilities at all times.

v. Work Practice. For carbon canisters/beds that are 20,000 pounds

or greater, as soon as breakthrough is detected, SDP shall ensure

that all emissions are vented to the secondary canister/bed and

shall monitor the outlet to the secondary canister/bed on an hourly

basis until the replacement canister is in place.

vi. Notify EPA about Monitored Parameter. In the first report due

under Paragraph 86 after installation of the carbon adsorption

system, SDP shall notify EPA about whether it is monitoring for

breakthrough using 50 ppm VOC or 1 ppm benzene.

App. 2.6 page 3 of 4

Case 4:13-cv-02009 Document 2-3 Filed in TXSD on 07/10/13 Page 28 of 54
APPENDIX 2.6

c. Anv Control Device Other than a Carbon Adsorption System. To the

extent that SDP installs or uses any control device other than or in addition to a carbon

adsorption system to comply with Subparagraph 2.6.8.a (e.g. SDP may install a carbon

adsorption system to control some part of the closed vent emissions and install or use a different

system to control other parts), such device must conform to the requirements of 40 C:F.R.

§ 61.349(a)(2)(i) or (ii) or (iii). In the first report due under Paragraph 85 after SDP has selected

a control device other than a Carbon Absorption System, SDP shall include a detailed description

of the control devices) it has selected, including how and where the device shall be incorporated

into the closed vent system, and a schematic identifying the location(s).

App. 2.6 page 4 of 4

Case 4:13-cv-02009 Document 2-3 Filed in TXSD on 07/10/13 Page 29 of 54
Exhibit 1 to Appendix 2.6

SHELL DEER PARK SITE

NORTH EFFLUENT TREATER

FLOW SCHEMATIC

OUTFACE

HOUSTON SHIP CHANNEL

Case 4:13-cv-02009 Document 2-3 Filed in TXSD on 07/10/13 Page 30 of 54
x 2.6

 SITE

R AREA

NORTH EFFLUENT

TREATER AREA ~

C

~'_"~3

~.

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7 ~ ~ ~ Ul~ou~

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;---- ~ ~—

-- La Port-Houstc

HighvraY 226

Case 4:13-cv-02009 Document 2-3 Filed in TXSD on 07/10/13 Page 31 of 54
UNITED STATES 

v. 

SHELL OIL COMPANY, ET AL. 

APPENDICES TO CONSENT DECREE 

APPENDIX 2.7 

MITIGATION PROJECT AT CERTAIN TANKS 

Case 4:13-cv-02009 Document 2-3 Filed in TXSD on 07/10/13 Page 32 of 54
APPENDIX 2.7

MITIGATION PROJECT: TANK CONTROLS

Tank Retirements, Retrofits, and Inspection

1. By no later than July 1, 2015, SDP shall take Tanks TOL-912 and TOL-913 permanently

out of service. Tanks TOL-912 and TOL-913 shall be replaced by existing Tanks

TOL-901 and TOL-911. Prior to July 1, 2015, Tanks TOL-901 and TOL-911 each shall

be retrofitted with aluminum geodesic domes to mitigate the effect of wind on emissions.

2. By no later than December 31, 2013, Shell shall take Tank TOL-920 temporarily out of

service for inspection. When out of service, SDP shall undertake a full internal

inspection and make any repairs necessary to assure that the tank is in good working

order and complies with all applicable regulatory control requirements.

Infrared Gas-Imaging Program for Tanks Associated with the ACUBEU

3. "ACU" shall mean the Aromatics Concentration Unit. "BEU" shall mean the Benzene

Extraction Unit. For the purpose of this Mitigation Project, "Tanks Associated with the

ACUBEU" or "Tanks" shall mean all tanks that receive or supply benzene or

benzene-containing material from/to the ACU or BEU and are located within the tank

farm denoted by "Aromatics Tank Farm" on the plot plan attached as Exhibit 1 to

Appendix 2.7. As of the Date of Lodging of this Consent Decree, the "Tanks Associated

with the ACU/BEU" are as follows:

Tank Service

D370 Benzene Service

D380 Benzene Service

D381 Benzene Service

D371 Benzene Service

L306 Benzene Service

D351 Benzene/Toluene Service

D352 Benzene/Toluene Service

J313 Benzene-Containing Service

D353 Benzene-Containing Service

D377 Reformate

D379 Refortnate

J312 Heavy Naphtha

J314 Benzene-Containing Service

D350 Benzene/Toluene Service

L305 Benzene/Toluene Service

4. During the life of this Consent Decree, the Tanks Associated with the ACUBEU may

change (e.g., tanks may be retired, taken out of ACUBEU service, or added to

ACUBEU service). Within 30 days of any such change, SDP shall send a notice to EPA

Page 1 of 5

Case 4:13-cv-02009 Document 2-3 Filed in TXSD on 07/10/13 Page 33 of 54
APPENDIX 2.7

updating the list of Tanks Associated with the ACUBEU. Such a change is not a

material modification of this Consent Decree.

5. Except as provided in the last sentence of this Paragraph, by no later than one month after

the Date of Entry of this Consent Decree, SDP shall commence a

once-every-two-calendar-weeks (i.e., bi-weekly) Infrared Gas-Imaging Program of the

Tanks Associated with the ACUBEU that are in-service (i.e., when hydrocarbons are in a

tank) using infrared gas-imaging cameras such as FLIR cameras or their equivalent. The

cameras used in this Program shall be capable of imaging organic gases that absorb

infrared light in approximately the 3.2 to 3.4 micron range, and have an automatic mode

(for thermal contrast and brightness) of gas imaging. For any specific tank, SDP shall not

be required to undertake the infrared gas-imaging required by this Paragraph during any

time period in which, pursuant to Subparagraph 9.b and the notice required in

Subparagraph 9.e, the tank is being repaired, is being removed from service, or is

removed from service.

6. The Infrared Gas-Imaging Program will be conducted by trained personnel who maintain

proficiency through regular use of the infrared gas-imaging camera. Prior to

implementation of the Program, personnel shall receive training in infrared gas-imaging

camera fundamentals and operation.

7. For the purpose of this Mitigation Project, the concept of "observing emissions" or

"emissions being observed" means any visual indication of organic gases on the screen of

an infrared gas-imaging camera.

8. Tank Ima~in~.

a. All imaging shall be done with the camera in automatic mode and shall be of all

vents of each tank. Imaging shall be done from the ground and conducted as

close as possible to the vent but at a distance of no more than 50 feet from a vent.

b. During each bi-weekly monitoring period, an initial imaging of each tank shall

take place regardless of whether the tank is filling, drawing down, or static.

i. If the imaging operator does not observe emissions during the initial

imaging, no further imaging of the tank is required in the monitoring

period.

ii. If the imaging operator observes emissions during the initial imaging, SDP

will idle the tank so its contents are static and then reimage the tank. If no

emissions are observed during the static imaging, no further actions are

required in the monitoring period.

iii. If emissions are observed during the static imaging, then SDP will proceed

with the requirements under Paragraph 9 of this Mitigation Project.

Page 2 of 5

Case 4:13-cv-02009 Document 2-3 Filed in TXSD on 07/10/13 Page 34 of 54
APPENDIX 2.7

9. Tank Inspection, Repair, and Notification. If emissions are observed during the static

tank imaging, SDP shall:

a. Conduct a visual inspection through manholes and roof hatches of the internal

floating roof, the primary seal, and secondary seals) (if one (or more) is in

service) within 48 hours of the static tank imaging that resulted in emissions being

observed.

b. If, during the inspection required by Subparagraph 9.a., the internal floating roof

is not resting on the surface of the liquid inside the.tank and is not resting on the

leg supports; or there is liquid on the floating roof; or the seals) is(are) detached;

or there are holes or tears in the seal fabric; or there are visible gaps between the

seals) and the wall of the tank, SDP shall repair all the items, or, if one or more

repairs cannot be made, shall empty and remove the tank from service within 45

calendar days. If the failures cannot be repaired or the tank cannot be emptied

within 45 calendar days, SDP may utilize no more than 2 extensions of no more

than 30 calendax days each. SDP may utilize an extension of time only if

alternate storage capacity is unavailable.

c. If, during the visual inspection required pursuant to Subparagraph 9.a, none of the

failures described in Subparagraph 9.b are observed, then no further action is

required unless and until the requirements of Subparagraph 9.d are met.

d. Tank Replacement/Dispute Resolution Invocation Requirements.

i. Applicability. The requirements of this Subparagraph apply only when:

(1) SDP has undertaken four static imaging events within a 26-week

period after the tank returns to service following a repair made

pursuant to Subparagraph 9.b;

(2) During each of those four events, emissions are observed

(Subparagraph 8.b.iii applies); and

(3) During each of the follow-up visual inspections to those four

events, no repairs are made pursuant to the timeframes in

Subparagraph 9.b.

ii. Tank Replacement/Dispute Resolution Invocation. If the applicability

requirements in Subparagraph 9.d.i are met, SDP must either:

(1) Replace the tank, in which case, SDP shall replace the tank by no

later than two years after the inspection triggering the replacement

requirement occurs; or

Page 3 of 5

Case 4:13-cv-02009 Document 2-3 Filed in TXSD on 07/10/13 Page 35 of 54
APPENDIX 2.7

(2) Invoke dispute resolution. Prior to invoking the dispute resolution

provisions of Section XII.A, SDP informally shall consult with

EPA for a period not to exceed 60 days. Thereafter, if the dispute

remains, SDP shall invoke the dispute resolution provisions of

Section XII.A. In any such dispute, SDP shall bear the burden of

demonstrating by substantial evidence that new, changed, or

previously unknown circumstances or information render it very

likely that if the tank were returned to service without being

replaced, emissions would not be observed from the tank for at

least 13 bi-weekly imaging events. For the duration of this

Consent Decree, SDP shall be entitled to invoke dispute resolution

on any tank only one time.

iii. Interim Period. Within 105 days after the inspection that triggers this

Subparagraph occurs: (1) SDP shall use best efforts to identify alternate

tank capacity that can be used continuously until the replacement tank is

available; or (2) if alternate tank capacity cannot be identified, SDP shall

submit a plan to EPA to minimize, to the extent practicable, the use of the

tank until the replacement tank is available. If (1) applies, SDP shall use

the alternate capacity until the replacement tank is available. If

(2) applies, SDP shall implement the plan.

e. SDP shall notify EPA in writing of the discovery of a tank failures) (as described

in paragraph 9.c.) within 30 days. Such notice shall describe in detail the tank

failure and SDP's detailed plans regarding repair of the tank and/or emptying of

the tank.

f. Within 10 days of the end of the origina145 day repair period and within 7 days

of the end of the first 30 day extension, SDP shall notify EPA in writing of a

decision to utilize an extension of time. Documentation of a decision to utilize an

extension shall include the reasons for the extension, an explanation about the

unavailability of alternate storage capacity, and a schedule of actions that will

ensure that the tank will be repaired or the tank will be emptied as soon as

practical.

g. After completion of the repairs done pursuant to subparagraph 9.b., SDP shall reimage the tank as verification that the tank is in good working order and complies

with all applicable regulatory control requirements.

10. In each Semi-Annual Report required pursuant to Section IX of this Consent Decree,

SDP shall include a narrative description of the infrared gas-imaging done pursuant to

this Mitigation Project, including but not limited to:

a. A certification that all Tanks Associated with the ACUBEU that were in-service

(i.e., that had hydrocarbons in the tank) at the time of the monitoring were

monitored in compliance with the terms of this Mitigation Project; an

Page 4 of 5

Case 4:13-cv-02009 Document 2-3 Filed in TXSD on 07/10/13 Page 36 of 54
APPENDIX 2.7

identification of each Tank Associated with the ACUBEU that was not

monitored, including an identification of how many bi-weekly monitoring

events) were not undertaken for the tank; and a certification that the Tanks

Associated with the ACUBEU that were not monitored during any monitoring

event were not in-service (i.e., did not have hydrocarbons in the tank) .

b. A record of the camera operator, date, time, weather conditions, tanks imaged,

and a written summary of the results (including identification of individual vent

and/or emission point locations). A notation should be made if a planned imaging

was not completed due to inclement weather, worker safety, or Force Majeure.

c. The infrared recordings (10 to 30 seconds) of any emissions observed during an

infrared gas imaging conducted pursuant to this Mitigation Project.

d. A record of what was done in response to the observation of emissions, including

inspection results and repairs.

Page5of5

Case 4:13-cv-02009 Document 2-3 Filed in TXSD on 07/10/13 Page 37 of 54
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Case 4:13-cv-02009 Document 2-3 Filed in TXSD on 07/10/13 Page 38 of 54
UNITED STATES 

v. 

SHELL OIL COMPANY, ET AL. 

APPENDICES TO CONSENT DECREE 

APPENDIX 2.8 

MITIGATION PROJECT AT THE ACU AND BEU 

Case 4:13-cv-02009 Document 2-3 Filed in TXSD on 07/10/13 Page 39 of 54
APPENDIX 2.8 

1 of 4 

MITIGATION PROJECT: ACU AND BEU CONTROLS

 2.8.1. By the dates set forth herein, SDP shall implement the Environmental Mitigation 

Project described in this Appendix 2.8 for the purpose of reducing emissions of hazardous air 

pollutants (“HAPs”) and volatile organic compounds (“VOCs”) from the Aromatic 

Concentration Unit (“ACU”) and the Benzene Extraction Unit (“BEU”). 

 2.8.2. PRV Review

 a. By no later than six months after the Date of Entry of this Consent Decree, 

SDP shall retain a third-party to undertake a review of the pressure relief valves (“PRVs”) in the 

ACU and BEU. Using the leak detection and repair (“LDAR”) database that is the most current 

one for the SDP Chemical Plant at the time this action is undertaken, as well as any other 

necessary documents (e.g., piping and instrumentation drawings, HON semi-annual reports), the 

third-party shall identify each pressure relief valve (“PRV”) in the ACU and BEU and shall 

review the operational parameters of, and applicable regulatory requirements for, each PRV. 

The third-party shall make at least the following determinations: 

(1) Location of the PRV 

(2) Size of the PRV 

(3) “State” of the process fluid in contact with the PRV (e.g., 

gas/vapor, light liquid, heavy liquid) 

(4) Whether the PRV is in vacuum service 

(5) Whether the PRV vents to the atmosphere 

(6) Appropriate monitoring frequency for the PRV 

(7) Appropriate monitoring method(s) for the PRV (e.g., Method 21, 

audio/visual/olfactory) 

(8) Each regulatory requirement applicable to the PRV 

 b. After completing its review, the third-party shall meet with SDP to discuss 

its determinations. The third-party and SDP shall make final decisions regarding each applicable 

regulatory requirement for each PRV. By no later than twelve months after the Date of Entry, 

SDP shall update its LDAR database as necessary to accurately reflect the final decisions made. 

 2.8.3. DTM and UTM Review

 a. By no later than six months after the Date of Entry of this Consent Decree, 

SDP shall retain a third-party to undertake a review of SDP’s designations of 

“difficult-to-monitor” (“DTM”) and “unsafe-to-monitor” (“UTM”) pieces of equipment in the 

Case 4:13-cv-02009 Document 2-3 Filed in TXSD on 07/10/13 Page 40 of 54
APPENDIX 2.8 

2 of 4 

ACU and BEU. Using the LDAR database that is the most current one for the SDP Chemical 

Plant at the time this action is undertaken, as well as any other necessary documents (e.g., piping 

and instrumentation drawings, HON semi-annual reports), the third-party shall identify each 

component that SDP lists as DTM and UTM in the ACU and BEU and shall review whether 

each such DTM and UTM designation is appropriate based on the applicable regulations for the 

component. 

 b. After completing its review, the third-party shall meet with SDP to discuss 

its determinations. The third-party and SDP shall make final decisions regarding each DTM and 

UTM designation. By no later than twelve months after the Date of Entry, SDP shall update its 

LDAR database as necessary to accurately reflect the final decisions made. 

 2.8.4. Comparative Monitoring 

 a. In a time period that is sufficient to enable SDP to meet the reporting 

requirements in Subparagraph 2.8.4.d and to try to meet the goal in the last sentence of 

Subparagraph 2.8.4.c, SDP shall retain a third-party to undertake comparative monitoring of the 

ACU and BEU. In undertaking the required monitoring, the third-party shall: 

i. Calculate a Comparative Monitoring Leak Percentage. The 

third-party shall calculate a leak percentage for the ACU and a leak 

percentage for the BEU, broken down by component type (e.g., 

valves, pumps, connectors, etc.). 

ii. Calculate the Historic, Average Leak Percentage from Prior 

Periodic Monitoring Events. The third-party shall calculate the 

historic, average leak percentage from prior periodic monitoring 

events in the ACU and BEU, broken down by component type 

(e.g., valves, pumps, connectors, etc.) but excluding pieces of 

equipment that were DTM and UTM during the monitoring 

periods used. The following number of complete monitoring 

periods immediately preceding the third-party’s comparative 

monitoring shall be used for this purpose: 

 Valves (including pressure relief valves) 4 periods 

 Pumps and Agitators 12 periods 

 Connectors 2 periods 

iii. Calculate the Comparative Monitoring Leak Ratio. For the ACU 

and the BEU, the third-party shall calculate the ratio of the 

Comparative Monitoring Leak Percentage (from Paragraph 2.8.5.a) 

to the Historic, Average Leak Percentage (from Paragraph 2.8.5.b). 

This ratio shall be called the “Comparative Monitoring Leak 

Ratio.” If, in calculating this ratio, the denominator is “zero,” it 

shall be assumed that one leaking piece of equipment was found 

Case 4:13-cv-02009 Document 2-3 Filed in TXSD on 07/10/13 Page 41 of 54
APPENDIX 2.8 

3 of 4 

through routine monitoring during the period before the 

comparative monitoring took place. 

 b. Comparative Monitoring Leak Ratio Report. In a time period that is 

sufficient to enable SDP to meet the reporting requirements in Subparagraph 2.8.4.d and to try to 

meet the goal in the last sentence of Subparagraph 2.8.4.c, the third-party shall submit a report to 

SDP that identifies the Comparative Monitoring Leak Ratios, broken down by component type, 

in the ACU and in the BEU. For any Comparative Monitoring Leak Ratio that is 3.0 or higher 

and where the Comparative Monitoring Leak Percentage is greater than or equal to 0.5, the 

third-party shall provide its opinion about possible causes and corrective actions. 

 c. Preliminary Corrective Action Plan (“Preliminary CAP”). In a time 

period that is sufficient to enable SDP to meet the reporting requirements in 

Subparagraph 2.8.4.d and to try to meet the goal in the last sentence of this Subparagraph 2.8.4.c, 

SDP shall develop a preliminary correction action plan for any Comparative Monitoring Leak 

Ratio that is 3.0 or higher and where the Comparative Monitoring Leak Percentage is greater 

than or equal to 0.5. The preliminary CAP shall describe the actions that SDP has taken or shall 

take to identify and address the causes of the high Comparative Monitoring Leak Ratio(s). SDP 

shall include a schedule by which corrective actions that have not yet been completed shall be 

completed. SDP shall complete each corrective action as expeditiously as practicable with the 

goal of completing each action by no later than twelve months after the Date of Entry. 

 d. Submission of Final CAP to EPA. In the first semi-annual report under 

Section XI of this Decree that is due no sooner than twelve months after the Date of Entry, SDP 

shall submit a final CAP to EPA, together with a certification of completion of each item of 

corrective action. If any item of corrective action is not completed at the time of the submission 

of this Final CAP, SDP shall explain the reasons, together with a schedule for prompt 

completion. SDP shall then submit a supplemental certification of completion those items of 

corrective action in the semi-annual report that is due for the period in which the action(s) 

was(were) completed. 

 2.8.5. Qualifications of Third-Party. For any actions in this Appendix 2.8 that must be 

undertaken by a “third-party,” SDP shall retain a company/consultant that has significant 

experience conducting LDAR compliance evaluations and Method 21 monitoring. The 

company/consultant must be a company different than the SDP Chemical Plant’s regular LDAR 

contractor. 

 2.8.6. Dual Mechanical Seals on Pumps. By no later than two years after the Date of 

Entry of this Consent Decree, SDP shall upgrade the following two pumps in the BEU with a 

dual mechanical seal system that meets all of the requirements of 40 C.F.R. § 63.163(e)(1)-(3): 

(1) G/0 PMP DP-2206 (E Sde of Ves V-900) (LDAR tag P0071); and (2) G/0 PMP DP-2207 

(E Sde of Ves V-900) (LDAR tag P0070). 

 

Case 4:13-cv-02009 Document 2-3 Filed in TXSD on 07/10/13 Page 42 of 54
APPENDIX 2.8 

4 of 4 

 2.8.7. FLIR Camera Protocol. 

a. By no later than one month after the Date of Entry of this Consent Decree, SDP 

shall commence an Infrared Gas-Imaging Program of the ACU and BEU using infrared gasimaging cameras such as FLIR cameras or their equivalent. The cameras used in this Program 

shall be capable of imaging organic gases that absorb infrared light in approximately the 3.2 to 

3.4 micron range, and have at least a high-sensitivity mode (enhanced detection) and automatic 

mode (for thermal contrast and brightness) of gas imaging. 

b. The Infrared Gas-Imaging Program shall be conducted by trained personnel who 

maintain proficiency through regular use of the infrared gas-imaging camera. Prior to 

implementation of the Program, personnel shall receive training in infrared gas-imaging camera 

use and operation. 

c. All ground level imaging shall be conducted at a distance of no more than 50 feet 

from the imaging target. 

d. For the purpose of this Appendix, the concept of “observing excess emissions” or 

“excess emissions being observed” means any visual indication of organic gases on the screen of 

an infrared camera. 

e. Observed excess emissions will monitored using Method 21. Components that 

exceed regulatory requirements will be repaired consistent with existing regulations. 

f. Infrared Gas-Imaging monitoring frequency for equipment that contains VOCs 

greater than 5% shall be as follows: 

i. Pumps – every two weeks 

ii. Atmospheric PRV’s – every two weeks 

iii. Valves – once per month 

iv. Connectors – once per quarter 

Case 4:13-cv-02009 Document 2-3 Filed in TXSD on 07/10/13 Page 43 of 54
UNITED STATES 

v. 

SHELL OIL COMPANY, ET AL. 

APPENDICES TO CONSENT DECREE 

APPENDIX 2.9 

FENCE LINE MONITORING SUPPLEMENTAL 

ENVIRONMENTAL PROJECT 

Case 4:13-cv-02009 Document 2-3 Filed in TXSD on 07/10/13 Page 44 of 54
APPENDIX 2.9

SCOPE OF WORK FOR THE SUPPLEMENTAL ENVIRONMENTAL

PROJECT: FENCE LINE OPEN-PATH MONITORING

("AIR MONITORING SOW")

Objectives

This Supplemental Environmental Project ("SEP") entails: (i) using an open-path

ambient air monitor to measure and record benzene concentrations in the ambient

air at the Covered Facilities' southeast fence line; (ii) using a Meteorological

Station to record weather variables simultaneously with pollutant measurements;

and (iii) responding with corrective actions to abate emissions.

Definitions

2. The following terms shall be defined as follows for the purposes of this Air

Monitoring SOW:

"Air Monitoring System" or "AMS" shall mean a system consisting of one

iJV DOAS Analyzer, one optical fiber multiplexer, two emitter telescopes,

and two receiver telescopes on the Covered Facilities' southeast fence

line, and a co-located Meteorological Station. These instruments shall be

configured so that the emitter and receiver telescopes create two 300 meter

paths in an east-west orientation; the Analyzer shall alternate

measurements between the two paths on an hourly basis by means of an

optical fiber multiplexer.

"Data Acquisition System" or "DAS" shall mean acomputer-based data

collection system that collects, organizes, and presents the data collected

by the AMS.

"Field Investigation" shall mean the investigatory process by which Shell

Deer Park ("SDP") attempts to determine all potential causes) of a

Screening Condition.

"Infrared Camera" shall mean an organic gas-imaging camera.

"Investigation Team" shall mean one or more SDP employees or

contractors that conduct Field Investigations in response to a Screening

Condition. SDP shall ensure that members of the Investigation Team,

before conducting a Field Investigation, have received appropriate training

necessary to enable the team members to tarty out their responsibilities on

the Investigation Team.

"Meteorological Station" shall mean a station that includes: (i) a 2-axis

sonic anemometer for measuring wind speed and direction; and

(ii) temperature and barometric pressure sensors for standardizing gas

Page 1 of 7

Case 4:13-cv-02009 Document 2-3 Filed in TXSD on 07/10/13 Page 45 of 54
APPENDIX 2.9

concentration data to volumetric (ppbV) concentrations. The

Meteorological Station shall be connected to the DAS. The data averaging

for the wind speed, wind direction, temperature, and barometric pressure

shall be timed to be contemporaneous with the 5-minute average gas

concentration measurements taken by the UV DOAS Analyzer. The

Meteorological Station shall be located away from structures so that wind

speed and direction measurements are representative of the measurement

site.

"Multiplexer" shall mean a device used to connect two optical paths to a

single UV DOAS Analyzer and to switch the measurements between one

path and the other.

"Portable PIDs" shall mean portable photo-ionization detectors. For

purposes of this SOW, Portable PIDs shall have a minimum sensitivity of

10 ppbV for organic gases measured as isobutylene.

"ppbV" shall mean parts per billion by volume normalized to standard

temperature and pressure.

"Screening Condition" shall mean SDP Relevant Data that consists of

either: (i) three or more 5-minute benzene concentration data points as

measured by the AMS within any one-hour period that are each 15 ppbV

or greater, provided that the five-minute average wind direction

measurements, taken contemporaneously with the three benzene

concentrations of 15 ppbV or greater within any one-hour period, are all

within a range of no more than 40 degrees azimuth when concentration is

plotted against the wind direction; or (ii) any one 5-minute benzene data

point as measured by the AMS that is greater than 50 ppbV.

"SDP Relevant Data" shall mean: (a) the 5-minute average benzene data.

points collected during periods when the wind direction was from 270 to

360 degrees; and (b) all wind speed and direction data.

"Toxic Vapor Analyzer" or "TVA" shall mean a portable flame-ionization

detector suitable for use in performing EPA Method 21.

"UV DOAS Analyzer" shall mean an open-path ultraviolet differential

optical absorption spectrometer that uses the unique absorption by

chemicals of specific wave lengths in the ultraviolet spectrum to identify

and quantify individual chemicals in the ambient air. For the purposes of

this SOW, the LTV DOAS Analyzer shall be capable of achieving a

detection limit of 3 ppbV for benzene and shall generate a data point for

average benzene concentration every 5-minutes. The 5-minute data point

for benzene shall represent an average of discreet data points collected

during the 5-minute averaging period.

Page 2 of 7

Case 4:13-cv-02009 Document 2-3 Filed in TXSD on 07/10/13 Page 46 of 54
APPENDIX 2.9

Minimum Equipment Requirements

3. In order to implement this SEP, SDP shall maintain in good working, order at the

Covered Facilities at least all of the following systems and equipment for the

duration of this SEP:

a. The A~VIS;

b. The DAS; and

c. Two Infrared Cameras, two Portable PIDs, and two TVAs.

AMS Equipment Configuration and Data Collection Requirements

4. The UV DOAS Analyzer shall be installed such that the optical paths it measures

have a generally east-west orientation as per the location identified in Exhibit 1 to

this Appendix.

5. The UV DOAS Analyzer shall be connected to a DAS that shall integrate the gas

concentration and meteorological data in order to show the gas-concentrationwind-direction correlations during any hour in which a Screening Condition

occurs.

6. The Meteorological Station shall be located neax the optical paths measured by

the AMS. The wind sensors (i) shall be located on a 10 meter mast unless

adjustments are required due to obstructions from the overpass located next to the

fence line, and (ii) shall, to the extent practicable, be positioned away from, or

above, obstructions such as buildings and process units that may interfere with

wind direction measurements.

7. All numerical data. collected for the duration of this SEP shall be stored and

maintained in a format that can be used in common spreadsheet programs.

Field Investigation — Minimum Requirements

8. Upon the occurrence of a Screening Condition, SDP shall begin a Field

Investigation as soon as possible but no later than 24 hours after the Screening

Condition. At a minimum, the Field Investigation shall include a review of the

data from the AMS and relevant operational data. from the Facility to locate the

potential sources) from which the emissions originated.

9. Upon identifying the general areas) from which the emissions originated, SDP

shall deploy an Investigation Team to the area(s). The Investigation Team shall

survey potential sources of the emissions by conducting a monitoring survey

using Portable PIDs and Infrared Cameras. Infrared Cameras shall be used in

high sensitivity mode Leve12. Method 21 monitoring will be conducted on leaks

identified by the Portable PIDs and Infrared Cameras. Confirmed emissions

Page 3 of 7

Case 4:13-cv-02009 Document 2-3 Filed in TXSD on 07/10/13 Page 47 of 54
APPENDIX 2.9

sources that exceed regulatory requirements shall be repaired as soon as

practicable. First attempt at repair of the confirmed emissions sources shall occur

no later than 5 days from the date of source identification by the Investigation

Team. Assessment of tanks shall be consistent with the protocols for tank

monitoring in Appendix 2.7 of this Consent Decree.

Compliance Status Determination and Corrective Action

10. By no later than 14 days after identifying, through a Field Investigation, a

benzene-emitting sources) that caused or contributed to a Screening Condition,

SDP shall determine whether the source is or was in violation of any applicable

federal, state, or local regulations or permit requirements. SDP shall implement,

as soon as practicable, corrective action to address any past or present

noncompliance.

11. If the compliance status determination in Paragraph 10 reveals that an identified

sources) of benzene is not in violation of any applicable regulation or permit

requirement, SDP shall evaluate the feasibility of reducing the emissions of

benzene from that source in order to minimize the potential recurrence of a future

Screening Condition from that source. In the Semi-Annual Reports required

pursuant to this SOW, SDP shall describe in detail the evaluation that it took and

identify any reduction measures considered, taken, and/or rejected.

Plans, Reports, and Schedule

12. No later than 120 days after the entry of this Consent Decree, SDP shall submit in

writing to EPA for review and approval an Air Monitoring Response Plan for the

Facility. This Plan shall include, but not be limited to:

a. A detailed description of the systems and equipment to be installed and

operated to implement this SOW. The systems and equipment shall be

consistent with the requirements set forth in Paragraphs 3 through 6 of this

SOW.

b. A QAPP that SDP shall implement to ensure the accuracy, validity,

representativeness, and usability of the data obtained by all monitoring

equipment, including the AMS, portable PIDs, TVAs, and Infrared

Cameras. The QAPP shall comply with the guidelines available in the

following publication: "EPA Requirements for Quality Assurance Project

Plans, EPA QA/R-5, March 2001."

Detailed standard operating procedures to be used during Field

Investigations.

d. A schedule—with a start date contingent upon approval of the Air

Monitoring Response Plan—for expeditiously purchasing, installing and

Page 4 of 7

Case 4:13-cv-02009 Document 2-3 Filed in TXSD on 07/10/13 Page 48 of 54
APPENDIX 2.9

commencing operation of the AMS, the DAS, the two Infrared Cameras,

the two Portable PIDs, and the two TVAs .

13. After EPA has completed its review and approval of the Air Monitoring Response

Plan, EPA shall send notice of its approval by certified mail, return receipt

requested, to the individuals listed for SDP in the Notice Section of this Consent

Decree. The "date of approval" of SDP's Air Monitoring Response Plan shall be

three days after the date of EPA's mailing.

14. SDP shall purchase or lease the equipment specified in the approved plan in

accordance with the schedule in the approved plan.

15. SDP shall complete the installation of all equipment specified in the Air

Monitoring Response Plan in accordance with the schedule in the approved. plan.

SDP shall promptly notify EPA when all of the specified equipment has been

installed. SDP shall not move the AMS to a new location without prior written

approval by EPA. Movement of AMS components for maintenance shall not be

restricted by this paragraph.

16. SDP shall commence operation of all monitoring equipment specified in the Air

Monitoring Response Plan in accordance with the schedule in the approved plan.

17. No later than 180 days after the AMS is operational, SDP shall begin conducting

Field Investigations into all Screening Conditions.

18. SDP may seek EPA approval to modify the Air Monitoring Response Plan at any

time during the effective period of this Consent Decree.

19. SDP shall submit Air Monitoring Semi-Annual Reports to EPA that contain the

following information:

a. In spreadsheet format, all data collected by the AMS. Data. shall include

time-synchronized concentration data and meteorological data which shall

be presented in contiguous columns on the spreadsheet. The first two

columns of each sheet shall be the date and time.

b. A detailed summary of each Field Investigation including:

i. The pertinent data collected during the Field Investigation,

including but not limited to: (a) measurement data collected by the

AMS, (b) recorded emissions imaged by the Infrared Cameras,

(c) portable PID data.; (d) TVA data; and (e) process data related to

the Investigation.

Page 5 of 7

Case 4:13-cv-02009 Document 2-3 Filed in TXSD on 07/10/13 Page 49 of 54
APPENDIX 2.9

ii. A detailed description of any actions taken by SDP to bring

sources into compliance and/or to reduce emissions in response to

the findings of a Field Investigation.

c. The calibration, maintenance, and other QA/QC results prepared pursuant

to the QAPP for all monitoring equipment required under this SEP.

d. In the period before the AMS is fully operational, SDP shall report on the

progress toward implementing this SEP.

20. The Air Monitoring Semi-Annual Reports shall be submitted contemporaneously

with the Semi-Annual Reports due under Paragraph 85 of the Decree with the first

Air Monitoring Semi-Annual Report due on the first reporting date that occurs

more than three months after the approved date for commencement of the

operation of the AMS. The Air Monitoring Semi-Annual Report shall be certified

in accordance with Paragraph 89 of the Consent Decree.

21. SDP shall post the Air Monitoring Semi-Annual Reports on the Internet, with any

confidential information redacted, at that same time as submission to EPA.

22. On a calendar week basis, SDP shall post to a publicly available Internet site the

SDP Relevant Data for the prior week. SDP shall post the SDP Relevant Data for

each calendar week no later than the last day of the following calendar week. The

data shall be presented in form that allows the benzene, wind speed, and wind

direction data to be viewed concurrently, i.e., in a tabular format.

23. On a calendar week basis, SDP shall e-mail the AMS and Meteorological Station

data that does not meet the definition "SDP Relevant Data" for that week to Cary

Secrest of EPA HQ (secrest.carvna,e~a.gov) and Dorothy Crawford of EPA

Region 6 (crawford.dorothy(u~epa. o~v). SDP shall e-mail the data for a calendar

week no later than the last day of the following calendar week. The data shall be

presented in form that allows the benzene, wind speed, and wind direction data. to

be viewed concurrently, i.e., in a tabular format.

24. SDP shall be required to correct deficient performance with the terms of this

SOW. Any disputes related to this SOW shall be resolved pursuant to the

procedures set forth in Section XII of this Consent Decree.

25. SDP shall comply with all terms of this Air Monitoring SOW and terms of the Air

Monitoring Response Plan for a period of two years starting with the date that

Field Investigations are required pursuant to Paragraph 17 above.

26. SDP shall submit to EPA a completion report on this SEP ("SEP Completion

Report") at the time specified in Paragraph 81 of the Consent Decree. In addition

to the information required in Paragraph 81, the SEP Completion Report for this

SEP shall include: (i) the same information required in an Air Monitoring

Page6of7

Case 4:13-cv-02009 Document 2-3 Filed in TXSD on 07/10/13 Page 50 of 54
APPENDIX 2.9

Semi-Annual Report; (ii) a summary of violations identified in the process of

implementing this SEP; and (iii) a summary of physical, process, and/or

operational changes made as a result of implementing this SEP.

Page 7 of 7

Case 4:13-cv-02009 Document 2-3 Filed in TXSD on 07/10/13 Page 51 of 54
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Case 4:13-cv-02009 Document 2-3 Filed in TXSD on 07/10/13 Page 52 of 54
UNITED STATES 

v. 

SHELL OIL COMPANY, ET AL. 

APPENDICES TO CONSENT DECREE 

APPENDIX 2.10 

DIESEL RETROFIT SUPPLEMENTAL 

ENVIRONMENTAL PROJECT 

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APPENDIX 2.10

Supplemental Environmental Project: Diesel Retrofit

 1. SDP shall implement a supplemental environmental project (“SEP”) in 

accordance with the criteria, terms and procedures specified in this Appendix 2.10 and in 

Section VIII (Supplemental Environmental Projects). 

 2. SDP may carry out its SEP responsibilities directly or through contractors 

selected by SDP. SDP shall ensure that all contractor costs related to the SEP are 

reasonable and necessary for completion of the SEP. 

 3. SDP shall spend no less than Two-Hundred Thousand Dollars ($200,000) to 

implement this SEP, which is to reduce emissions generated by diesel-powered school 

buses and non-school bus publicly-owned vehicles in the area of SDP’s refinery and 

chemical plant (“Covered Facilities”) in Deer Park, Texas. 

 4. All SEP funds shall be spent on the purchase and installation of United States 

Environmental Protection Agency (“EPA”) and/or California Air Resources Board (“CARB”) 

verified retrofit and idle reduction technologies. SEP funds creditable toward meeting the 

minimum $200,000 expenditure shall cover only the hardware and installation cost of 

retrofit and idle reduction technologies. 

 5. All SEP funds shall be spent for technologies to be installed on school buses 

or publicly owned vehicles located within 50 miles of the Covered Facilities and, limited to, 

and in the order of, the following priorities: 

(1) School buses in Harris County 

(2) Non-school bus publicly owned vehicles in Harris County 

(3) School buses in Brazoria, Chambers, Fort Bend, Galveston, Liberty, 

and Montgomery counties 

(4) Non-school bus publicly owned vehicles in Brazoria, Chambers, Fort 

Bend, Galveston, Liberty, and Montgomery counties 

 6. Implementation of this SEP project shall be completed within twenty-four 

(24) months after the Date of Entry of this Consent Decree. 

 7. SDP shall seek to coordinate the selection of projects and the funding of 

projects with relevant and applicable state and local officials where possible, but SDP 

retains responsibility for performance of the SEP. 

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